Purchased Power
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | | | | | | | Change from | | | | | | | | | Change from | |
| | | 2009 | | | 2008 | | | Prior Year % | | | 2009 | | | 2008 | | | Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Purchased Power | | $ | 288,248 | | | $ | 319,324 | | | | -9.7 | % | | $ | 541,746 | | | $ | 577,161 | | | | -6.1 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Purchased power in thousands of MWhs | | | 2,553 | | | | 3,406 | | | | -25.0 | % | | | 5,345 | | | | 6,435 | | | | -16.9 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average cost per MWh of purchased power | | $ | 112.91 | | | $ | 93.75 | | | | 20.4 | % | | $ | 101.36 | | | $ | 89.69 | | | | 13.0 | % |
Purchased power costs decreased for the three and nine months ended September 30, 2009 compared to the same period in 2008 primarily due to a decrease in volume and lower natural gas prices partially offset by an increase in the settlement costs for hedging instruments related to tolling contracts. Volume decreased primarily as a result of an increase in self generation. The average cost per MWh increased primarily due to an increase in settlement costs for hedging instruments, partially offset by a decrease in lower natural gas prices.
Deferral of Energy Costs - Net
| | | Three Months | | | Nine Months | |
| | | Ended September 30, | | | Ended September 30, | |
| | | 2009 | | | 2008 | | | Change from Prior Year % | | | 2009 | | | 2008 | | | Change from Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Deferred energy costs - net | | $ | 46,911 | | | $ | (80,191 | ) | | | -158.5 | % | | $ | 144,910 | | | $ | (44,107 | ) | | | -428.5 | % |
Deferral of energy costs – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferral of energy costs – net also include the current amortization of fuel and purchased power costs previously deferred. Reference Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.
Amounts for the three months ended September 30, 2009 and 2008 include amortization of deferred energy costs of $14.7 million and $35.7 million, respectively; and an over-collection of amounts recoverable in rates of $32.2 million in 2009 and an under-collection of $115.9 million in 2008. Amounts for the nine months ended September 30, 2009 and 2008 include amortization of deferred energy costs of $33.5 million and $123.9 million, respectively; and an over-collection of amounts recoverable in rates of $111.4 million in 2009 and an under-collection of $168 million in 2008. Amortization for both the three and nine month periods include amounts for the Western Energy Crisis Rate Case and the reinstatement of deferred energy as discussed in Note 3, Regulatory Actions, of Notes to Financial Statements in NPC’s 2008 Form 10-K.
Allowance for Funds Used During Construction (AFUDC)
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | | | Change from Prior Year % | | | 2009 | | | 2008 | | | Change from Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Allowance for other funds used during construction | | $ | 3,385 | | | $ | 6,543 | | | | -48.3 | % | | $ | 16,558 | | | $ | 21,093 | | | | -21.5 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Allowance for borrowed funds used during construction | | $ | 2,815 | | | $ | 5,128 | | | | -45.1 | % | | $ | 13,483 | | | $ | 16,503 | | | | -18.3 | % |
| | | $ | 6,200 | | | $ | 11,671 | | | | -46.9 | % | | $ | 30,041 | | | $ | 37,596 | | | | -20.1 | % |
AFUDC decreased for the three months and nine months ended September 30, 2009, compared to the same period in 2008, due to the completion of construction of the Clark Peaking Units in late 2008, partially offset by the construction of the 500 MW natural gas generating units at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011.
Other (Income) and Expenses
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | | | Change from Prior Year % | | | 2009 | | | 2008 | | | Change from Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Other operating expense | | $ | 68,521 | | | $ | 69,432 | | | | -1.3 | % | | $ | 206,771 | | | $ | 189,144 | | | | 9.3 | % |
| Maintenance expense | | $ | 12,014 | | | $ | 12,469 | | | | -3.6 | % | | $ | 58,280 | | | $ | 42,727 | | | | 36.4 | % |
| Depreciation and amortization | | $ | 54,996 | | | $ | 37,902 | | | | 45.1 | % | | $ | 160,869 | | | $ | 120,855 | | | | 33.1 | % |
| Interest charges on long-term debt | | $ | 56,672 | | | $ | 46,662 | | | | 21.5 | % | | $ | 166,492 | | | $ | 129,283 | | | | 28.8 | % |
| Interest charges-other | | $ | 4,498 | | | $ | 6,737 | | | | -33.2 | % | | $ | 17,526 | | | $ | 17,952 | | | | -2.4 | % |
| Interest accrued on deferred energy | | $ | (248 | ) | | $ | (2,803 | ) | | | -91.2 | % | | $ | (2,891 | ) | | $ | (5,681 | ) | | | -49.1 | % |
| Other income | | $ | (3,776 | ) | | $ | (4,116 | ) | | | -8.3 | % | | $ | (18,726 | ) | | $ | (12,970 | ) | | | 44.4 | % |
| Other expense | | $ | 1,537 | | | $ | 2,028 | | | | -24.2 | % | | $ | 12,335 | | | $ | 5,045 | | | | 144.5 | % |
Other operating expense decreased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to a decrease in legal and other external services costs, and bad debt expense due to a lower reserve rate. These decreases were partially offset by an increase to pension expense, costs associated with renewable energy programs, operating leases and operating expenses for the Higgins Generating Station acquired in October 2008.
Other operating expense increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to an increase in pension expense, costs associated with renewable energy programs, operating leases and operating expenses for the Higgins Generating Station acquired in October 2008, partially offset by lower outside legal and other external services costs.
Maintenance expense decreased slightly for the three months ended September 30, 2009, compared to the same period in 2008, due to decreased costs for the Clark and Lenzie Generating Stations due to planned outages in 2008, partially offset by increased costs for the Higgins Generating Station acquired in October 2008.
Maintenance expense increased for the nine months ended September 30, 2009, compared to the same period in 2008, due to the addition of the Higgins Generating Station and increased scheduled maintenance for the Clark, Lenzie, Navajo, Reid Gardner and Silverhawk Generating Stations in 2009.
Depreciation and amortization expenses increased during the three months and nine months ended September 30, 2009, compared to the same period in 2008, as a result of increases in plant-in-service, primarily due to the completion of the Clark Peaking Units and the addition of the Higgins Generating Station in the latter part of 2008.
Interest charges on Long-Term Debt increased for the three months and nine months ended September 30, 2009, compared to the same period in 2008, primarily due to the issuance of additional debt used to fund significant capital expenditures. This increase was partially offset by lower interest on variable rate debt. See Note 6, Long-Term Debt of the Notes to Financial Statements in the 2008 Form 10-K and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q for additional information regarding long-term debt.
Interest charges-other decreased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to a change in estimated interest expense on uncertain tax positions recorded in the first quarter of 2009 which were subsequently reversed in the third quarter. Also contributing to the decrease in 2009 was interest expense associated with refunds for construction advances recorded in 2008. These decreases were partially offset by higher amortization costs related to new debt issues and redemptions. Interest charges-other for the nine months ended September 30, 2009, compared to the same period in 2008, decreased due to interest expense associated with refunds for construction advances recorded in 2008, offset by higher amortization costs related to new debt issues and redemptions.
Interest income accrued on deferred energy balances decreased for the three months and nine months ended September 30, 2009, as compared to the same period in 2008, due to lower carrying charges associated with NPC’s Western Energy Crisis Rate Case, which began June 1, 2007, and overall lower deferred energy balances. See Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further details of deferred energy balances.
Other income decreased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to lower carrying charges on energy conservation programs and lower interest income on investments. These decreases were partially offset by interest income received on income tax refunds. Other income increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to the settlement of outstanding legal matters associated with the Natural Gas Provider case, as discussed further in Note 7, Commitments and Contingencies of the Condensed Notes to Financial Statements, interest received on tax refunds, and higher carrying charges on energy conservation programs. These were partially offset by expiration of the amortization of gains associated with the disposition of property, lower interest income on investments and income earned in 2008 as a result of the settlement with Calpine, and the subsequent gain on sale of the stock received, as discussed further in Note 13, Commitments and Contingencies, in the Notes to Financial Statements in the 2008 Form 10-K.
Other expense decreased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to lower advertising expenses in 2009. Other expense increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to adjustments resulting from the decision in NPC’s GRC. The increase in other expense for the nine months ended September 30, 2009, was also partially offset by lower advertising expenses in 2009.
ANALYSIS OF CASH FLOWS
Cash flows decreased during the nine months ended September 30, 2009, compared to the same period in 2008, due to reduction in cash from financing activities and a slight increase in cash used for investing activities, partially offset by an increase in cash from operating activities.
Cash From Operating Activities. The increase in cash from operating activities was due primarily to the over collection of revenues in excess of fuel and purchased power costs, decreased purchased power and fuel costs, increased BTGR revenues beginning July 1, 2009, and the settlement of outstanding litigation. These increases were partially offset by increased operating and maintenance costs for new generating facilities, some of which were not included in rates until July 1, 2009, pension funding, increased interest costs, the receipt of prepaid transmission revenue in 2008 and the repayment of transmission deposits in 2009.
Cash Used By Investing Activities. Cash used for investing activities did not change significantly between the periods.
Cash From Financing Activities. Cash from financing activities decreased primarily due to a decrease in investment by NVE and increased payments on the revolving credit facility. This decrease was partially offset by the issuance of $625 million in Series U and Series V Notes.
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory matters and economic conditions.
| Available Liquidity as of September 30, 2009 (in millions) | |
| | | | |
| Cash and Cash Equivalents | | $ | 30.8 | |
Balance available on Revolving Credit Facility(1) | | $ | 555.3 | |
| | | $ | 586.1 | |
1 As of October 28, 2009, NPC had approximately $653.3 million available under its revolving credit facilities, which reflects amounts outstanding under letters of credit.
NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, NPC may use its revolving credit facilities in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facilities, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below. NPC anticipates with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the NPC’s revolving credit facilities, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less. In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE.
The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.
NPC does not have significant debt maturities in 2009 or 2010 other than its revolving credit facilities. NPC’s long-term credit facility expires on November 4, 2010, and NPC’s $90 million Supplemental Revolving Credit Facility expires on January 3, 2010. As of October 28, 2009, NPC has borrowed approximately $10 million on its revolving credit facility.
There have been no changes to the credit ratings of NPC in the first three quarters of 2009, other than DBRS’ election to discontinue coverage on a majority of their U.S. clients (see Credit Ratings, below). However, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.
During the nine months ended September 30, 2009, there were no material changes to contractual obligations as set forth in NPC’s 2008 Form 10-K, except as discussed under financing transactions below.
Financing Transactions
Tender Offer
On October 7, 2009, NPC settled its cash tender offer, which commenced on September 8, 2009 and expired on October 5, 2009 for the following securities:
| • | | Clark County, Nevada Industrial Development Refunding Revenue Bonds (Nevada Power Company Project) Series 2000A, in an aggregate principal amount of $100 million; |
| • | | Coconino County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2006A, in an aggregate principal amount of $40 million; and |
| • | | Clark County, Nevada Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2006, in an aggregate principal amount of $39.5 million (collectively, “the NPC Bonds”). |
Those holders who tendered their NPC Bonds by the expiration date were entitled to receive a purchase price of $900 per $1,000 NPC Bond, plus any accrued and unpaid interest to, but not including, the date that is two business days following the October 5, 2009 expiration date. Approximately $5.7 million of the $179.5 million NPC Bonds outstanding were validly tendered and accepted by NPC. NPC financed the tendered bonds with available cash. The tendered NPC Bonds remain outstanding and have not been retired or cancelled. However, as NPC is the sole holder of the NPC Bonds, for financial reporting purposes the investment in the tendered NPC Bonds to the indebtedness will be offset for presentation purposes.
Maturity of Clark County Nevada Pollution Control Revenue Bonds, Series 2000B
On October 1, 2009 the Clark County Nevada Pollution Control Revenue Bonds, Series 2000B, in the aggregate principal amount of $15 million, matured. In July 2008, these securities were converted from auction rate securities to variable rate demand notes, as further disclosed in Note 6, Long-Term Debt in the 2008 Form 10-K. NPC purchased 100% of the bonds at that time, and remained the sole holder of these bonds until the maturity date. NPC financed the maturity with available cash.
Revolving Credit Facilities
On March 2, 2009, NPC amended its $600 million Second Amended and Restated Revolving Credit Agreement, which matures in November 2010, to remove a bankrupt lending bank from the facility. This amendment reduced the capacity of the facility to approximately $589 million.
On January 5, 2009, NPC entered into a new $90 million supplemental revolving credit facility. The facility has a term of 364 days, and is secured by General and Refunding Mortgage bonds. This credit facility matures in January 2010, and is in addition to NPC’s existing approximate $589 million revolving credit facility.
General and Refunding Mortgage Notes, Series V
On March 2, 2009, NPC issued and sold $500 million of its 7.125% General and Refunding Mortgage Notes, Series V due 2019. The net proceeds of the issuance were used to repay approximately $404 million of amounts outstanding under NPC’s approximate $589 million revolving credit facility, and for general corporate purposes.
General and Refunding Mortgage Notes, Series U
On January 12, 2009, NPC issued and sold $125 million of its 7.375% General and Refunding Mortgage Notes, Series U due 2014. The net proceeds of the issuance were used to repay approximately $124 million of amounts outstanding under NPC’s approximate $589 million revolving credit facility.
Factors Affecting Liquidity
Ability to Issue Debt
NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of certain NVE debt. As of September 30, 2009, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $750 million in long-term debt, in addition to the use of its existing credit facilities. However, depending on NVE’s or SPPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities the PUCN authority may not remain the most restrictive factor. The factors affecting NPC’s ability to issue debt are further detailed below:
| a. | Financing authority from the PUCN - As of September 30, 2009, NPC has financing authority from the PUCN to issue (1) additional long term debt up to $750 million over a two-year period ending December 31, 2010, (2) ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and (3) authority to refinance up to approximately $471 million of long-term debt securities; |
| b. | Financial covenants within NPC’s financing agreements - NPC's $589 million Second Amended and Restated Revolving Credit Agreement dated November 2005, and its $90 million supplemental Revolving Credit Agreement, dated January 5, 2009, each contain two financial maintenance covenants. The first requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of September 30, 2009, NPC was in compliance with these covenants. In order to maintain compliance with these covenants, NPC is limited to $2 billion of additional indebtedness. All other financial covenants contained in NPC’s revolving credit facilities and its financing agreements are suspended, as NPC’s senior secured debt is rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these covenants; and |
| c. | Financial Covenants within NVE’s financing agreements - As discussed in NVE’s Ability to Issue Debt, NPC is subject to NVE’s cap on additional consolidated indebtedness of $828 million. |
Ability to Issue General and Refunding Mortgage Securities
To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under NPC’s Indenture.
NPC’s Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of September 30, 2009, $4.0 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $646 million of additional General and Refunding Mortgage Securities as of September 30, 2009. That amount is determined on the basis of:
| 1. | | 70% of net utility property additions; |
| 2. | | the principal amount of retired General and Refunding Mortgage Securities; and/or |
| 3. | | the principal amount of first mortgage bonds retired after October 2001. |
Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.
NPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of NPC’s Indenture, it will reduce the amount of securities issuable under NPC’s Indenture.
Credit Ratings
NPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering NPC. As of September 30, 2009, the ratings are as follows:
| | | | Rating Agency |
| | | | Fitch | | Moody’s | | S&P |
| NPC | Sr. Secured Debt | | BBB-* | | Baa3* | | BBB* |
| NPC | Sr. Unsecured Debt | | BB | | Not rated | | BB+ |
* Investment grade
S&P’s and Moody’s rating outlook for NPC is Stable. Fitch’s rating outlook is Positive.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.
Cross Default Provisions
None of the financing agreements of NPC contains a cross-default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of their respective financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.
Energy Supplier Matters
With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.
Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of September 30, 2009 for all suppliers continuing to provide power under a WSPP agreement would approximate a $67.0 million payment or obligation to NPC. These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.
Gas Supplier Matters
With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counterparties require payment in advance of delivery.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. For this counterparty, if NPC’s senior secured ratings from both Moody’s and S&P are below investment grade, the maximum collateral amount would be $46.1 million. If NPC’s senior unsecured rating from both Moody’s and S&P are below investment grade, the maximum collateral requirement would be $11.5 million.
Financial Gas Hedges
NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that NPC maintain its Moody’s and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that NPC’s Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require NPC to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to NPC, subject to certain caps. As of September 30, 2009, the maximum amount of collateral NPC would be required to post under these agreements is approximately $45.0 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $36.8 million would be required if NPC is downgraded one level, and an additional amount of approximately $8.2 million would be required if NPC is downgraded two levels.
RESULTS OF OPERATIONS
SPPC recognized net income of $24.3 million for the three months ended September 30, 2009 compared to net income of $32.9 million for the same period in 2008. During the nine months ended September 30, 2009, SPPC recognized net income of approximately $58.2 million compared to $68.1 million for the same period in 2008.
During the nine months ended September 30, 2009, SPPC paid $128.8 million in dividends to NVE.
Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.
SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less energy costs, provides a measure of income available to support the other operating expenses of SPPC. For reconciliation to operating income, see Note 2, Segment Information in the Condensed Notes to Financial Statements. Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect SPPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.
The components of gross margin were (dollars in thousands):
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | | | | | | | Change from | | | | | | | | | Change from | |
| | | 2009 | | | 2008 | | | Prior Year % | | | 2009 | | | 2008 | | | Prior Year % | |
| Operating Revenues: | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 265,734 | | | $ | 271,919 | | | | -2.3 | % | | $ | 734,386 | | | $ | 758,612 | | | | -3.2 | % |
| Gas | | | 19,745 | | | | 19,379 | | | | 1.9 | % | | | 132,686 | | | | 137,125 | | | | -3.2 | % |
| | | $ | 285,479 | | | $ | 291,298 | | | | -2.0 | % | | $ | 867,072 | | | $ | 895,737 | | | | -3.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy Costs: | | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel for power generation | | $ | 89,125 | | | $ | 92,845 | | | | -4.0 | % | | $ | 229,119 | | | $ | 211,137 | | | | 8.5 | % |
| Purchased power | | | 25,580 | | | | 64,005 | | | | -60.0 | % | | | 92,439 | | | | 251,474 | | | | -63.2 | % |
| Deferral of energy costs-electric-net | | | 26,646 | | | | (9,384 | ) | | | -384.0 | % | | | 68,222 | | | | (12,572 | ) | | | -642.7 | % |
| Gas purchased for resale | | | 11,269 | | | | 13,760 | | | | -18.1 | % | | | 101,457 | | | | 108,288 | | | | -6.3 | % |
| Deferral of energy costs-gas-net | | | 2,286 | | | | (725 | ) | | | -415.3 | % | | | 1,923 | | | | (2,296 | ) | | | -183.8 | % |
| | | $ | 154,906 | | | $ | 160,501 | | | | -3.5 | % | | $ | 493,160 | | | $ | 556,031 | | | | -11.3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy Costs by Segment: | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 141,351 | | | $ | 147,466 | | | | -4.1 | % | | $ | 389,780 | | | $ | 450,039 | | | | -13.4 | % |
| Gas | | | 13,555 | | | | 13,035 | | | | 4.0 | % | | | 103,380 | | | | 105,992 | | | | -2.5 | % |
| | | $ | 154,906 | | | $ | 160,501 | | | | -3.5 | % | | $ | 493,160 | | | $ | 556,031 | | | | -11.3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross Margin by Segment: | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 124,383 | | | $ | 124,453 | | | | -0.1 | % | | $ | 344,606 | | | $ | 308,573 | | | | 11.7 | % |
| Gas | | | 6,190 | | | | 6,344 | | | | -2.4 | % | | | 29,306 | | | | 31,133 | | | | -5.9 | % |
| | | $ | 130,573 | | | $ | 130,797 | | | | -0.2 | % | | $ | 373,912 | | | $ | 339,706 | | | | 10.1 | % |
Gross margin – electric and gas, decreased slightly for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to an increase in rates offset by a decrease in customer usage as a result of milder weather.
Gross margin - - electric increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to the increase in BTGR revenue as a result of SPPC’s 2007 GRC, effective July 1, 2008, increased revenues associated with renewable energy programs, and a slight increase in average customer growth. Partially offsetting the increase was a decrease in customer usage as a result of milder weather, a decrease in short-term transmission revenue and the switching of certain mining customers to DOS.
Gross margin – gas decreased for the nine months ended September 30, 2009 compared to the same period in 2008 primarily due to decreased customer usage as a result of milder weather.
Electric Operating Revenue
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | | | | | | | Change from | | | | | | | | | Change from | |
| | | 2009 | | | 2008 | | | Prior Year % | | | 2009 | | | 2008 | | | Prior Year % | |
| Electric operating revenues: | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 93,594 | | | $ | 96,558 | | | | -3.1 | % | | $ | 263,287 | | | $ | 256,726 | | | | 2.6 | % |
| Commercial | | | 108,167 | | | | 108,596 | | | | -0.4 | % | | | 296,671 | | | | 289,327 | | | | 2.5 | % |
| Industrial | | | 56,328 | | | | 59,163 | | | | -4.8 | % | | | 151,671 | | | | 187,942 | | | | -19.3 | % |
| Retail revenues | | | 258,089 | | | | 264,317 | | | | -2.4 | % | | | 711,629 | | | | 733,995 | | | | -3.0 | % |
| Other | | | 7,645 | | | | 7,602 | | | | 0.6 | % | | | 22,757 | | | | 24,617 | | | | -7.6 | % |
| Total revenues | | $ | 265,734 | | | $ | 271,919 | | | | -2.3 | % | | $ | 734,386 | | | $ | 758,612 | | | | -3.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Retail sales in thousands of MWhs | | | 2,206 | | | | 2,339 | | | | -5.7 | % | | | 6,128 | | | | 6,537 | | | | -6.3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average retail revenue per MWh | | $ | 116.99 | | | $ | 113.00 | | | | 3.5 | % | | $ | 116.13 | | | $ | 112.28 | | | | 3.4 | % |
SPPC’S retail revenues decreased for the three and nine months ended September 30, 2009 as compared to the same period in 2008 primarily due to lower industrial revenue and decreased customer usage due to cooler summer weather and in the case of the nine month period, milder spring weather and warmer winter weather. Industrial revenues decreased primarily due to the transition of Cortez Mine to DOS effective November 1, 2008, and a retail service agreement with Newmont Mining Corporation (“Newmont”) beginning June 1, 2008. These decreases were partially offset by increased retail rates. Retail rates increased as a result of SPPC’s GRC effective July 1, 2008.
In 2007, SPPC and Newmont entered into a wholesale power sale agreement and a new form of retail service, whereby Newmont will sell the electrical output from its generating plant to SPPC for at least 15 years under a long-term wholesale purchase power agreement and remain a retail customer of SPPC during at least that period under the terms of the retail service agreement and pursuant to a new rate schedule. The terms of these contracts became effective on June 1, 2008 at which point Newmont moved to a new retail service agreement at a reduced energy rate, which resulted in decreased electric revenues.
For the three months ended September 30, 2009, the average number of residential and industrial customers decreased 0.1% and 3.0%, respectively, while the commercial customers increased 1.9%. For the nine months ended September 30, 2009, the average number of residential customers decreased 0.1% and the average number of commercial and industrial customers increased 1.6% and 1.9%, respectively.
Electric Operating Revenues – Other increased for the three months ended September 30, 2009, compared to the same period in 2008 primarily due to the amortization of Cortez Mine impact fees related to the departure of Cortez from SPPC’s system. Electric Operating Revenues – Other decreased for the nine month period primarily due to decreased transmission revenues which were partially offset by the amortization of the Cortez fees.
Gas Operating Revenues
| | | Three Months | | | Nine Months | |
| | | Ended September 30, | | | Ended September 30, | |
| | | | | | Change from | | | | | | Change from | |
| | | 2009 | | | 2008 | | | Prior Year % | | | 2009 | | | 2008 | | | Prior Year % | |
| Gas operating revenues: | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 10,740 | | | $ | 10,269 | | | | 4.6 | % | | $ | 74,410 | | | $ | 79,074 | | | | -5.9 | % |
| Commercial | | | 4,913 | | | | 4,885 | | | | 0.6 | % | | | 35,191 | | | | 37,768 | | | | -6.8 | % |
| Industrial | | | 2,155 | | | | 1,873 | | | | 15.1 | % | | | 11,779 | | | | 13,726 | | | | -14.2 | % |
| Retail revenues | | | 17,808 | | | | 17,027 | | | | 4.6 | % | | | 121,380 | | | | 130,568 | | | | -7.0 | % |
| Wholesale revenue | | | 1,406 | | | | 1,858 | | | | -24.3 | % | | | 9,567 | | | | 4,663 | | | | 105.2 | % |
| Miscellaneous | | | 531 | | | | 494 | | | | 7.5 | % | | | 1,739 | | | | 1,894 | | | | -8.2 | % |
Total revenues | | $ | 19,745 | | | $ | 19,379 | | | | 1.9 | % | | $ | 132,686 | | | $ | 137,125 | | | | -3.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Retail sales in thousands of Dths | | | 1,183 | | | | 1,231 | | | | -3.9 | % | | | 9,549 | | | | 10,420 | | | | -8.4 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average retail revenue per Dth | | $ | 15.05 | | | $ | 13.83 | | | | 8.8 | % | | $ | 12.71 | | | $ | 12.53 | | | | 1.4 | % |
SPPC’s retail gas revenues increased for the three months ended September 30, 2009 as compared to the same period in the prior year primarily due to increased retail rates. Retail rates increased as a result of SPPC’s various Natural Gas and Propane BTER quarterly updates. The average number of retail customers for the three months ended September 30, 2009 increased 0.3%.
SPPC’S retail gas revenues decreased for the nine months ended September 30, 2009 as compared to the same period in 2008 primarily due to decreased customer usage as a result of warmer winter weather and lower rates prior to April 1, 2009. The average number of retail customers for the nine months ended September 30, 2009 increased 0.3%.
Wholesale revenues decreased for the three month period ended September 30, 2009, compared to the same period in 2008 primarily due to decreased availability of gas for wholesale sales. Wholesale revenues increased for the nine months ended September 30, 2009, compared to prior year due to increased availability of gas for wholesale sales during the first and second quarter of 2009.
Energy Costs
Energy Costs include Purchased Power and Fuel for Generation. These costs are dependent upon many factors which may vary by season or period. As a result, SPPC’s usage and average cost per MWh of Purchased Power versus Fuel for Generation can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:
| • | | Weather |
| • | | Plant outages |
| • | | Total system demand |
| • | | Resource constraints |
| • | | Transmission constraints |
| • | | Gas transportation constraints |
| • | | Natural gas constraints |
| • | | Long-term contracts |
| • | | Mandated power purchases; and |
| • | | Generation efficiency |
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | | | | | | | Change from | | | | | | | | | Change from | |
| | | 2009 | | | 2008 | | | Prior Year % | | | 2009 | | | 2008 | | | Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Energy Costs | | $ | 114,705 | | | $ | 156,850 | | | | -26.9 | % | | $ | 321,558 | | | $ | 462,611 | | | | -30.5 | % |
| Total System Demand | | | 2,352 | | | | 2,455 | | | | -4.2 | % | | | 6,590 | | | | 6,986 | | | | -5.7 | % |
| Average cost per MWh | | $ | 48.77 | | | $ | 63.89 | | | | -23.7 | % | | $ | 48.79 | | | $ | 66.22 | | | | -26.3 | % |
Energy costs and the average cost per MWh for the three and nine months ended September 30, 2009 decreased compared to the same period in 2008 due to the significant decrease in natural gas prices and lower purchase power costs during the first six months of 2009 as a result of the Newmont Mining Corporation power purchase agreement discussed above in Electric Operating Revenues. Total system demand decreased due to milder weather, certain customers switching to DOS and a change in customer usage patterns. For the three months ended September 30, 2009, self generation represented 72% of total system compared to 61% for the same period in 2008. For the nine months ended September 30, 2009, self generation represented 64% of total system compared to 47% for the same period in 2008.
Fuel for Power Generation
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | | | | | | | Change from | | | | | | | | | Change from | |
| | | 2009 | | | 2008 | | | Prior Year % | | | 2009 | | | 2008 | | | Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Fuel for power generation | | $ | 89,125 | | | $ | 92,845 | | | | -4.0 | % | | $ | 229,119 | | | $ | 211,137 | | | | 8.5 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Thousands of MWh generated | | | 1,696 | | | | 1,478 | | | | 14.7 | % | | | 4,219 | | | | 3,325 | | | | 26.9 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average fuel cost per MWh of generated power | | $ | 52.55 | | | $ | 62.82 | | | | -16.3 | % | | $ | 54.31 | | | $ | 63.50 | | | | -14.4 | % |
Fuel for power generation and average cost per MWh decreased for the three months ended September 30, 2009 as compared to the same period in 2008 due primarily to lower natural gas prices partially offset by an increase in the settlement costs for hedging instruments. The volume increased due to greater reliance on internal generation.
Fuel for power generation and volume increased for the nine months ended September 30, 2009 as compared to the same period in 2008 due to a greater reliance on the Tracy Generation Station. The average cost per MWh decreased for the nine months primarily due to lower natural gas prices partially offset by an increase in the settlement costs for hedging instruments.
Purchased Power
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | | | | | | | Change from | | | | | | | | | Change from | |
| | | 2009 | | | 2008 | | | Prior Year % | | | 2009 | | | 2008 | | | Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Purchased power | | $ | 25,580 | | | $ | 64,005 | | | | -60.0 | % | | $ | 92,439 | | | $ | 251,474 | | | | -63.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Purchased power in thousands of MWhs | | | 656 | | | | 977 | | | | -32.9 | % | | | 2,371 | | | | 3,661 | | | | -35.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average cost per MWh of purchased power | | $ | 38.99 | | | $ | 65.51 | | | | -40.5 | % | | $ | 38.99 | | | $ | 68.69 | | | | -43.2 | % |
Purchased power costs and the average cost per MWh decreased for the three months ended September 30, 2009 as compared to the same period in 2008 primarily due to a decrease in natural gas prices. The volume of MWhs decreased for the three months ended September 30, 2009 as compared to the same period in 2008 primarily due to increased reliance on internal generation.
Purchased power costs and the average cost per MWh decreased for the nine months ended September 30, 2009 as compared to the same period in 2008 primarily due to a decrease in natural gas prices and a power purchase agreement with Newmont Mining Corporation, as discussed above in Electric Operating Revenues, whereby SPPC purchases power substantially below current market prices. However, SPPC is limited by the volume it can purchase under these lower rates. The volume of MWhs decreased for the nine months ended September 30, 2009 as compared to the same period in 2008 primarily due to increased reliance on internal generation.
Gas Purchased for Resale
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | | | | | | | Change from | | | | | | | | | Change from | |
| | | 2009 | | | 2008 | | | Prior Year % | | | 2009 | | | 2008 | | | Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Gas purchased for resale | | $ | 11,269 | | | $ | 13,760 | | | | -18.1 | % | | $ | 101,457 | | | $ | 108,288 | | | | -6.3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas purchased for resale (in thousands of Dths) | | | 1,670 | | | | 1,510 | | | | 10.6 | % | | | 12,141 | | | | 11,221 | | | | 8.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average cost per Dth | | $ | 6.75 | | | $ | 9.11 | | | | -25.9 | % | | $ | 8.36 | | | $ | 9.65 | | | | -13.4 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Gas purchased for resale and average cost per decatherm decreased for the three months and nine months ended September 30, 2009 as compared to the same period in 2008. The decrease is primarily due to a decrease in natural gas prices. Volume increased for the three and nine months ended September 30, 2009 compared to the same period in 2008 primarily due to excess availability of gas, due to milder weather. The excess is sold to wholesale customers.
Deferral of Energy Costs – Electric - Net
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | | | Change from Prior Year % | | | 2009 | | | 2008 | | | Change from Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Deferred energy costs - electric – net | | $ | 26,646 | | | $ | ( 9,384 | ) | | | -384.0 | % | | $ | 68,222 | | | $ | (12,572 | ) | | | -642.7 | % |
| Deferred energy costs - gas – net | | $ | 2,286 | | | $ | (725 | ) | | | - 415.3 | % | | $ | 1,923 | | | $ | (2,296 | ) | | | -183.8 | % |
| | | $ | 28,932 | | | $ | (10,109 | ) | | | | | | $ | 70,145 | | | $ | (14,868 | ) | | | | |
Deferral of energy costs – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates the difference is recognized as an increase in costs. Deferral of energy costs – net also include the current amortization of fuel and purchased power costs previously deferred Reference Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.
Deferral of energy costs - electric – net for the three months ended September 30, 2009 and 2008 reflect amortization of deferred energy costs of $(0.4) million and $(2.0) million respectively; and an over-collection of amounts recoverable in rates of $27.0 million in 2009, and an under-collection of $7.4 million in 2008. For the nine months ended September 30, 2009 and 2008, amortization of deferred energy costs were ($1.6) million and $16.6 million, respectively; with an over-collection of amounts recoverable in rates of $69.8 million in 2009, and under-collection of $29.2 million in 2008.
Deferred energy costs - gas - net for the three months ended September 30, 2009 and 2008 reflect amortization of deferred energy costs of $0.0 million, and ($0.1) million, respectively; and an over-collection of amounts recoverable in rates in 2009 of $2.3 million and an under-collection of $0.6 million in 2008. For the nine months ended September 30, 2009 and 2008, amortization of deferred energy costs were $0.0 million and ($1.0) million, respectively; with an over-collection of amounts recoverable in rates of $1.9 million and under-collection of $1.3 million, respectively.
Allowance for Funds Used During Construction (AFUDC)
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | | | Change from Prior Year % | | | 2009 | | | 2008 | | | Change from Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Allowance for other funds used during construction | | $ | 942 | | | $ | 1,322 | | | | -28.8 | % | | $ | 2,535 | | | $ | 11,842 | | | | -78.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Allowance for borrowed funds used during construction | | $ | 864 | | | $ | 1,050 | | | | -17.7 | % | | $ | 2,364 | | | $ | 8,915 | | | | -73.5 | % |
| | | $ | 1,806 | | | $ | 2,372 | | | | -23.9 | % | | $ | 4,899 | | | $ | 20,757 | | | | -76.4 | % |
AFUDC decreased for the three and nine months ended September 30, 2009 compared to the same period in 2008, primarily due to the completion of the Tracy Generating Station in July of 2008, which resulted in a decrease to the Construction Work-In-Progress (CWIP) balance.
Other (Income) and Expense
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | | | Change from Prior Year % | | | 2009 | | | 2008 | | | Change from Prior Year % | |
| | | | | | | | | | | | | | | | | | | |
| Other operating expense | | $ | 38,843 | | | $ | 35,474 | | | | 9.5 | % | | $ | 123,748 | | | $ | 103,744 | | | | 19.3 | % |
| Maintenance expense | | $ | 8,173 | | | $ | 7,868 | | | | 3.9 | % | | $ | 23,939 | | | $ | 22,204 | | | | 7.8 | % |
| Depreciation and amortization | | $ | 27,545 | | | $ | 21,343 | | | | 29.1 | % | | $ | 80,043 | | | $ | 64,801 | | | | 23.5 | % |
| Interest charges on long-term debt | | $ | 16,760 | | | $ | 18,635 | | | | -10.1 | % | | $ | 49,820 | | | $ | 55,975 | | | | -11.0 | % |
| Interest charges-other | | $ | 891 | | | $ | 1,407 | | | | -36.7 | % | | $ | 4,017 | | | $ | 4,398 | | | | -8.7 | % |
| Interest accrued on deferred energy | | $ | 2,047 | | | $ | 454 | | | | 350.9 | % | | $ | 3,764 | | | $ | 1,639 | | | | 129.7 | % |
| Other income | | $ | (3,792 | ) | | $ | (2,367 | ) | | | 60.2 | % | | $ | (12,299 | ) | | $ | (11,331 | ) | | | 8.5 | % |
| Other expense | | $ | 813 | | | $ | 749 | | | | 8.5 | % | | $ | 4,601 | | | $ | 5,430 | | | | -15.3 | % |
Other operating expense increased for the three and nine months ended September 30, 2009, compared to the same period in 2008, primarily due to higher pension expense, costs related to renewable energy programs and operating expenses for the Tracy Generating Station expansion placed in service in summer 2008. Additionally, contributing to higher expenses was lower provisions for bad debt in 2008 compared to 2009.
Maintenance expense increased for the three and nine months ended September 30, 2009, compared to the same period in 2008, primarily due to the addition of the Tracy Generating Station expansion that became operational in summer of 2008, partially offset by outages at Valmy Generating Station for boiler repairs in 2008 and lower maintenance cost for Ft. Churchill in 2009.
Depreciation and amortization expenses increased for the three and nine months ended September 30, 2009 compared to the same period in 2008, as a result of increases in plant-in-service, primarily due to the completion of the Tracy Generating Station in July of 2008.
Interest charges on long-term debt decreased for the three months and nine months ended September 30, 2009 compared to the same periods in 2008 primarily due to interest savings related to repurchased debt, lower interest rates on variable rate debt, and the redemption of $99 million Series A General and Refunding Mortgage Bonds in June 2008. These amounts were partially offset by the issuance of $250 million Series Q General and Refunding Mortgage Notes in September 2008, and the addition of $150 million to its 6.0% Series M General and Refunding Mortgage Notes in August 2009. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2008 10-K and Note 4, Long-Term Debt, of the Condensed Notes to Financial Statements in this Form 10-Q for additional information regarding long-term debt .
Interest charges-other decreased for the three months and nine months ended September 30, 2009, compared to the same period in 2008, due to several items, none of which are material.
Interest expense accrued on deferred energy balances increased for the three months and nine months ended September 30, 2009, compared to the same period in 2008, due to higher deferred energy balances in 2009. See Note 3, Regulatory Actions of the Condensed Notes to Financial Statements for further details of deferred energy balances.
Other income increased for the three months ended September 30, 2009, compared to the same period in 2008, primarily due to interest received for income tax refunds, offset by lower miscellaneous carrying charges. Other income increased for the nine months ended September 30, 2009, compared to the same period in 2008, primarily due to gains on the disposition of property in 2009 and interest received for tax refunds, offset by income earned in 2008 related to the reinstatement of previously disallowed costs associated with Pinon Pine and the settlement with Calpine as discussed in Note 3, Regulatory Actions and Note 13, Commitments and Contingencies of the Notes to Financial Statements in the 2008 Form 10-K.
Other expense increased for the three months ended September 30, 2009, compared to the same period in 2008, due to several items, none of which are material. Other expense decreased during the nine months ended September 30, 2009, when compared to the same period in 2008, due to lower advertising costs in 2009 and adjustments resulting from the decision in SPPC’s GRC in 2008. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2008 10-K for further information.
ANALYSIS OF CASH FLOWS
Cash flows increased during the nine months ended September 30, 2009 compared to the same period in 2008 due to an increase in cash from operating activities and a decrease in cash used by investing activities, partially offset by a decrease in cash from financing activities.
Cash From Operating Activities. The increase in cash from operating activities was primarily due to the over collection of revenues in excess of fuel and purchased power costs, an increase in BTGR revenues as a result of SPPC’s 2007, GRC, partially offset by funding of pension plans and higher balances for fuel and purchased power costs at year end December 31, 2008, that were subsequently paid in 2009.
Cash Used By Investing Activities. Cash used by investing activities did not change significantly between the periods.
Cash From Financing Activities. The decrease in cash from financing activities is primarily due to increased dividends paid to the holding company, NVE and the reacquisition of $40 million Series 2007A variable rate notes due 2036, partially offset by the issuance of $150 million Series M notes and the investment by parent.
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory matters and economic conditions.
| Available Liquidity as of September 30, 2009 (in millions) | |
| Cash and Cash Equivalents | | $ | 58.4 | |
Balance available on Revolving Credit Facility(1) | | $ | 316.1 | |
| | | $ | 374.5 | |
1 As of October 28, 2009, SPPC had approximately $316.9 million available under its revolving credit facility, which reflects amounts outstanding under letters of credit.
SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, SPPC may use its revolving credit facility in order to meet its liquidity needs. SPPC anticipates with the reduction in cash requirements for capital expenditures, as discussed earlier, and decreasing commodity prices, that cash on hand, internally generated funds and the ability to issue debt, which includes the use of the SPPC’s revolving credit facility, will be sufficient to meet short-term operating costs. However, if energy costs rise at a rapid rate and SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less. In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE.
The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.
SPPC does not have significant debt maturities in 2009 or 2010 other than its revolving credit facility. SPPC’s long-term credit facility expires on November 4, 2010. As of October 28, 2009, SPPC does not have any borrowings outstanding on its revolving credit facility.
There have been no changes to the credit ratings of SPPC in the first three quarters of 2009, other than DBRS’ election to discontinue coverage on a majority of their U.S. clients (see Credit Ratings, below). However, disruptions in the banking and capital markets not specifically related to SPPC may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.
During the nine months ended September 30, 2009, there were no material changes to contractual obligations as set forth in SPPC’s 2008 Form 10-K, except as discussed under financing transactions below.
Financing Transactions
Tender Offer
On October 7, 2009, SPPC settled its cash tender offer, which commenced on September 8, 2009 and expired on October 5, 2009 for the following securities:
| • | | Washoe County, Nevada Gas Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006A, in an aggregate principal amount of $58.7 million; |
| • | | Washoe County, Nevada Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006B, in an aggregate principal amount of $75 million; and |
| • | | Washoe County, Nevada Gas and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2006C, in an aggregate principal amount of $84.8 million (collectively, “the SPPC Bonds”). |
Those holders who tendered their SPPC Bonds by the expiration date were entitled to receive a purchase price of $900 per $1,000 SPPC Bond, plus any accrued and unpaid interest to, but not including, the date that is two business days following the October 5, 2009 expiration date. Approximately $3.8 million of the $218.5 million SPPC Bonds outstanding were validly tendered and accepted by SPPC. SPPC financed the tendered bonds with available cash. The tendered SPPC Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the SPPC Bonds, for financial reporting purposes the investment in the tendered SPPC Bonds and the indebtedness will be offset for presentation purposes.
General and Refunding Mortgage Notes, Series M
On August 21, 2009, SPPC issued an additional $150 million in aggregate principal amount of its 6% General and Refunding Mortgage Notes, Series M, as part of the same series as the original Series M Notes issued in March 2006. Upon the issuance of these Notes, the aggregate principal amount of the Series M Notes outstanding is $450 million. The proceeds from the second issuance were used to repay amounts outstanding under SPPC’s revolving credit facility.
Revolving Credit Facility
On March 2, 2009, SPPC amended its $350 million Amended and Restated Revolving Credit Agreement, due November 2010, to remove a bankrupt lending bank from the facility. This amendment reduced the capacity of the facility to approximately $332 million.
Conversion of Washoe County Water Facilities Refunding Revenue Bonds
In January 2009, SPPC converted the $40 million principal amount, Washoe County, Nevada Water Facilities Refunding Revenue Bonds Series 2007A bonds, due 2036 (the “Water Bonds”) from auction rate securities to variable rate demand notes. The purpose of the conversion was to reduce interest costs and volatility associated with these bonds. SPPC purchased 100% of the Water Bonds on that date, with the use of its revolving credit facility and available cash, and will remain the sole holder of the Water Bonds, until such time as SPPC determines to reoffer the Water Bonds to investors. These Water Bonds remain outstanding and have not been retired or cancelled. However, as SPPC is the sole holder of the Water Bonds, for financial reporting purposes the investment in the Water Bonds and the indebtedness will be offset for presentation purposes.
Factors Affecting Liquidity
Ability to Issue Debt
SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt. As of October 28, 2009, the most restrictive of the factors below is the PUCN authority, based on this restriction, SPPC may issue up to $350 million of long-term debt securities, and maintain a credit facility up to $600 million. However, depending on NVE’s or NPC’s issuance of long-term debt or the use of Utilities’ revolving credit facilities the PUCN authority may not remain the most restrictive factor. The factors affecting SPPC’s ability to issue debt are further detailed below:
| a. | Financing authority from the PUCN - On October 28, 2009, the PUCN approved SPPC’s request for financing authority to issue up to $350 million of long-term debt securities over a three-year period ending December 31, 2012, ongoing authority to maintain a revolving credit facility of up to $600 million, and authority to refinance up to approximately $348 million of long-term debt securities; |
| b. | Financial covenants within SPPC’s financing agreements - SPPC's $332 million Amended and Restated Revolving Credit Agreement dated November 2005, contains two financial maintenance covenants. The first requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. The second requires SPPC to maintain a ratio of consolidated cash flow to consolidated interest expense, determined as of the last day of each fiscal quarter for the period of four consecutive fiscal quarters, not to be less than 2.0 to 1. As of September 30, 2009, SPPC was in compliance with these covenants. In order to maintain compliance with these covenants, SPPC is limited to $735 million of additional indebtedness. All other financial covenants contained in SPPC’s revolving credit facility and financing agreements are suspended, as SPPC’s senior secured debt is rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations on indebtedness under these covenants; and |
| c. | Financial covenants within NVE’s financing agreements - Furthermore, as discussed in NVE’s Ability to Issue Debt, SPPC is subject to NVE’s cap on additional consolidated indebtedness of $828 million. |
Ability to Issue General and Refunding Mortgage Securities
To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under SPPC’s Indenture.
SPPC’s Indenture creates a lien on substantially all of SPPC’s properties in Nevada and California. As of September 30, 2009, $1.8 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $495 million of additional General and Refunding Mortgage Securities as of September 30, 2009. That amount is determined on the basis of:
| 1. | 70% of net utility property additions; |
| 2. | the principal amount of retired General and Refunding Mortgage Securities; and/or |
| 3. | the principal amount of first mortgage bonds retired after October 2001. |
Property Additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.
SPPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of SPPC’s Indenture, it will reduce the amount of securities issuable under SPPC’s Indenture.
Credit Ratings
SPPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering SPPC. As of September 30, 2009, the ratings are as follows:
| | | | Rating Agency |
| | | | Fitch | | Moody’s | | S&P |
| SPPC | Sr. Secured Debt | | BBB-* | | Baa3* | | BBB* |
* Investment grade
S&P’s, and Moody’s rating outlook for SPPC is Stable. Fitch’s rating outlook is Positive.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.
Cross Default Provisions
None of the financing agreements of SPPC contains a cross-default provision that would result in an event of default by SPPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.
Energy Supplier Matters
With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.
Under these contracts, a material adverse change (e.g., a credit rating downgrade) in SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. Under the net mark-to-market value as of September 30, 2009 for all suppliers continuing to provide power under a WSPP agreement no amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Notes to Financial Statements for further discussion.
Gas Supplier Matters
With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse change, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Because of creditworthiness concerns, most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counterparties require payment in advance of delivery.
Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service.
Financial Gas Hedges
SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. The contracts require that SPPC maintain its Moody’s and S&P Senior Unsecured or equivalent ratings in place at the time the contracts were entered into. In the event that SPPC’s Senior Unsecured debt rating is downgraded by two out of the three rating agencies, the counterparties have the right to require SPPC to post cash or a letter of credit to the extent the counterparties have mark-to-market exposure to SPPC, subject to certain caps. As of September 30, 2009, the maximum amount of collateral SPPC would be required to post under these agreements is approximately $37.3 million based on mark-to-market values, which are substantially based on quoted market prices. Of this amount, approximately $27.3 million would be required if SPPC is downgraded one level and an additional amount of approximately $10.0 million would be required if SPPC is downgraded two levels.
REGULATORY PROCEEDINGS (UTILITIES)
NVE is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, NVE and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC, the PUCN and the CPUC. In addition, the PUCN, the CPUC or the FERC have the authority to review allocations of costs of non-power goods and administrative services among NVE and its subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between NVE, NPC and/or SPPC and/or any other affiliated company.
The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric distribution and transmission operations. NPC and SPPC submit IRPs to the PUCN for approval.
Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.
As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.
The Utilities are required to file annual electric and gas DEAA cases on March 1 as mandated by the 2007 Nevada Legislature, quarterly BTER Updates for the Utilities’ electric and gas departments, and triennial GRCs in Nevada. A DEAA case is filed to recover or refund any under or over collection of prior energy costs and the BTER Updates recover current energy costs. As of September 30, 2009, NPC’s and SPPC’s balance sheets included approximately $137 million and over-collections of $104 million, respectively, of deferred energy costs, which $247 million and over-collections of $33 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. Refer to Note 3, Regulatory Actions of the Condensed Notes to Financial Statements. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.
Rate case applications filed in 2008 and 2009, as well as other regulatory matters such as the Utilities’ IRPs and subsequent amendments, other Nevada matters, California matters and FERC matters, are discussed in more detail in Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, and in the 2008 Form 10-K.
RECENT PRONOUNCEMENTS
See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements, for discussion of accounting policies and recent pronouncements.
ITEM 3A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
As of September 30, 2009, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).
September 30, 2009
| | | | | Expected Maturity Date | | | | |
| | | | | | | | | | | | | | | | | | | Fair |
| | | | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | Thereafter | | Total | | Value |
| Long-term Debt | | | | | | | | | | | | | | | | |
| | NVE | | | | | | | | | | | | | | | | | |
| | Fixed Rate | | $ - | | $ - | | $ - | | $ 63,670 | | $ - | | $ 421,539 | | $ 485,209 | | $ 505,090 |
| | Average Interest Rate | - | | - | | - | | 7.80% | | - | | 7.77% | | 7.78% | | |
| | | | | | | | | | | | | | | | | | | |
| | NPC | | | | | | | | | | | | | | | | | |
| | Fixed Rate | | $ - | | $ - | | $ 364,000 | | $ 130,000 | | $ - | | $ 2,894,335 | | $ 3,388,335 | | $ 3,690,086 |
| | Average Interest Rate | - | | - | | 8.14% | | 6.50% | | - | | 6.53% | | 6.70% | | |
| | Variable Rate | | $ - | | $ 108,000 | | $ - | | $ - | | $ - | | $ 179,500 | | $ 287,500 | | $ 287,500 |
| | Average Interest Rate | - | | 1.27% | | - | | - | | - | | 1.08% | | 1.15% | | |
| | | | | | | | | | | | | | | | | | | |
| | SPPC | | | | | | | | | | | | | | | | | |
| | Fixed Rate | | $ - | | $ - | | $ - | | $ 100,000 | | $ 250,000 | | $ 775,000 | | $ 1,125,000 | | $ 1,200,460 |
| | Average Interest Rate | - | | - | | - | | 6.25% | | 5.45% | | 6.31% | | 6.12% | | |
| | Variable Rate | | $ - | | $ - | | $ - | | $ - | | $ - | | $ 218,500 | | $ 218,500 | | $ 218,500 |
| | Average Interest Rate | - | | - | | - | | - | | - | | 1.11% | | 1.11% | | |
| | | | | | | | | | | | | | | | | | | |
| | Total Debt | | $ - | | $ 108,000 | | $ 364,000 | | $ 293,670 | | $ 250,000 | | $ 4,488,874 | | $ 5,504,544 | | $ 5,901,636 |
Commodity Price Risk
See the 2008 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2008.
Credit Risk
The Utilities monitor and manage credit risk with their counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with counterparties was approximately $73.7 million as of September 30, 2009, compared to amounts of $334.3 million at December 31, 2008, and $266.3 million at September 30, 2008. The decrease is primarily due to lower market prices for physical electric contracts and lower contract prices for natural gas contracts.
| (a) | Evaluation of disclosure controls and procedures. |
NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of September 30, 2009, the registrants’ disclosure controls and procedures were effective.
| (b) | Change in internal controls over financial reporting. |
There were no changes in internal controls over financial reporting in the third quarter of 2009 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
PART II
As of the date of this report, there have been no material changes with regard to administrative and judicial proceedings involving regulatory, environmental and other matters as disclosed in NVE’s, NPC’s and SPPC’s 2008 Form 10-K, and quarterly reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009, except as discussed below.
Nevada Power Company and Sierra Pacific Power Company
Western United States Energy Crisis Proceedings before the FERC
FERC 206 complaints
In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers, including Enron, under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in June 2001 in reaction to the Western United States energy crisis. The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power against terminating suppliers.
In June 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. In July 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June decision (“July decision”). The Utilities appealed this decision to the Ninth Circuit. In December 2006, a three judge panel of the Ninth Circuit overturned the July decision and remanded the case back to the FERC for application of the factors that the Ninth Circuit outlines in its decision. In May 2007, American Electric Power Service Corporation and Allegheny Energy Supply Company and other interested parties filed petitions for certiorari (“Petitions”) with the U.S. Supreme Court seeking review of the Ninth Circuit’s decision. The Utilities, together with other parties and the FERC, filed their opposition to these Petitions in August 2007. In September 2007, the U.S. Supreme Court granted certiorari. In June 2008, the U.S. Supreme Court rejected the Ninth Circuit’s reasoning in reversing the FERC but nonetheless found that FERC’s order was defective and should be reversed for other reasons. The case was remanded to the FERC. The FERC established a formal settlement discussion protocol for bilateral settlement discussions with other respondents, including Allegheny Energy Supply Company, American Electric Power Service Corporation and BP Energy, and stayed the case pending settlement discussions. The Utilities, together with other interested parties, have settled and resolved all claims against BP Energy (“BP Settlement”). On August 25, 2009, the BP Settlement received final approval by the FERC to which BP Energy was ordered to settle with NPC for an immaterial amount in return for NPC and the BCP’s release of all claims against BP Energy. On September 15, 2009, the Utilities, together with other interested parties, reached an agreement in principle with American Electric Power Service Corporation (“AEP Settlement”). The Utilities previously had negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy, now known as El Paso Marketing L.P., Calpine Energy Services and Enron. The Utilities continue discussions with Allegheny Energy Supply Company. Management cannot predict the timing or outcome of a decision in this matter.
Other Legal Matters
NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on their financial positions or results of operations. See Note 7, Commitments and Contingencies, in the Condensed Notes to Financial Statements for further discussion of other legal matters.
For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC). The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2008 Form 10-K. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.
As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2008 Form 10-K, and quarterly reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
None.
| (a) | Exhibits filed with this Form 10-Q: |
(12) NV Energy, Inc.:
Nevada Power Company:
Sierra Pacific Power Company:
(31) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company
(32) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
| | | | | |
| | | NV Energy, Inc. |
| | | (Registrant) |
| | | | | |
| Date: October 29, 2009 | | By: | | /s/ William D. Rogers |
| | | | | William D. Rogers |
| | | | | Chief Financial Officer |
| | | | | (Principal Financial Officer) |
| | | | | |
| Date: October 29, 2009 | | By: | | /s/ E. Kevin Bethel |
| | | | | E. Kevin Bethel |
| | | | | Chief Accounting Officer |
| | | | | (Principal Accounting Officer) |
| | | | | |
| | | Nevada Power Company d/b/a NV Energy |
| | | (Registrant) |
| | | | | |
| Date: October 29, 2009 | | By: | | /s/ William D. Rogers |
| | | | | William D. Rogers |
| | | | | Chief Financial Officer |
| | | | | (Principal Financial Officer) |
| | | | | |
| Date: October 29, 2009 | | By: | | /s/ E. Kevin Bethel |
| | | | | E. Kevin Bethel |
| | | | | Chief Accounting Officer |
| | | | | (Principal Accounting Officer) |
| | | | | |
| | | Sierra Pacific Power Company d/b/a NV Energy |
| | | (Registrant) |
| | | | | |
| Date: October 29, 2009 | | By: | | /s/ William D. Rogers |
| | | | | William D. Rogers |
| | | | | Chief Financial Officer |
| | | | | (Principal Financial Officer) |
| | | | | |
| Date: October 29, 2009 | | By: | | /s/ E. Kevin Bethel |
| | | | | E. Kevin Bethel |
| | | | | Chief Accounting Officer |
| | | | | (Principal Accounting Officer) |
