(EDGAR Online via COMTEX) -- Item 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management's narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).
The following discussion and analysis by management focuses on those factors that had a material effect on NSP-Minnesota's financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes to the consolidated financial statements. Due to the seasonality of NSP-Minnesota's electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.
Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "believe," "estimate," "expect," "intend," "may," "objective," "outlook," "plan," "project," "possible," "potential," "should" and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting NSP-Minnesota's nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including "Risk Factors" in Item 1A of NSP-Minnesota's Form 10-K for the year ended Dec. 31, 2012, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2013.
Results of Operations
NSP-Minnesota's net income was approximately $334.8 million for the nine months ended Sept. 30, 2013, compared with approximately $277.3 million for the same period in 2012. Earnings were positively impacted by electric rate increases in Minnesota, South Dakota and North Dakota interim rates, subject to refund, and lower interest charges. These were partially offset by higher O&M expenses and property taxes.
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Electric Revenues and Margin Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin: Nine Months Ended Sept. 30 (Millions of Dollars) 2013 2012 Electric revenues $ 3,080 $ 2,913 Electric fuel and purchased power (1,270 ) (1,176 ) Electric margin $ 1,810 $ 1,737
The following tables summarize the components of the changes in electric revenues and electric margin for the nine months ended Sept. 30:
Electric Revenues (Millions of Dollars) 2013 vs. 2012 Retail rate increases (a) $ 101 Fuel and purchased power cost recovery 67 Transmission revenue 37 Estimated impact of weather 15 Conservation program incentives (14 ) Conservation program revenue (offset by expenses) (13 ) Retail sales decrease (excluding weather impact) (11 ) Other, net (15 ) Total increase in electric revenues $ 167 Electric Margin (Millions of Dollars) 2013 vs. 2012 Retail rate increases (a) $ 101 Transmission revenue, net of costs 22 Estimated impact of weather 15 Conservation program incentives (14 ) Conservation program revenue (offset by expenses) (13 ) Retail sales decrease (excluding weather impact) (11 ) Other, net (27 ) Total increase in electric margin $ 73
(a) The retail rate increases include final rates in Minnesota and South Dakota and interim rates, subject to refund, in North Dakota. The Minnesota rate increase is net of a provision for customer refunds of $69 million for the third quarter of 2013 and $116 million for the nine months ended Sept. 30, 2013 based on the final rate order received for the 2013 electric rate case. In addition, revenues and expenses were reduced by approximately $30 million, primarily related to depreciation expense of $24 million and O&M expenses of $6 million in the third quarter of 2013 due to the order. See Note 5 to the consolidated financial statements for further discussion.
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Natural Gas Revenues and Margin The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details natural gas revenues and margin: Nine Months Ended Sept. 30 (Millions of Dollars) 2013 2012 Natural gas revenues $ 396 $ 305 Cost of natural gas sold and transported (247 ) (179 ) Natural gas margin $ 149 $ 126
The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the nine months ended Sept. 30:
Natural Gas Revenues (Millions of Dollars) 2013 vs. 2012 Purchased natural gas adjustment clause recovery $ 68 Estimated impact of weather 15 Conservation program revenue (offset by expenses) 4 Retail sales increase (excluding weather impact) 3 Other, net 1 Total increase in natural gas revenues $ 91 Natural Gas Margin (Millions of Dollars) 2013 vs. 2012 Estimated impact of weather $ 15 Conservation program revenue (offset by expenses) 4 Retail sales increase (excluding weather impact) 3 Other, net 1 Total increase in natural gas margin $ 23
Non-Fuel Operating Expenses and Other Items O&M Expenses - O&M expenses increased $51.5 million, or 6.4 percent, for the nine months ended Sept. 30, 2013 compared with the same period in 2012. The following table summarizes the changes in O&M expenses for the nine months ended Sept. 30: (Millions of Dollars) 2013 vs. 2012 Nuclear plant operations and amortization $ 28 Electric and gas distribution expenses 10 Information technology costs 7 Interchange agreement billing with NSP-Wisconsin 5 Transmission costs 4 Employee benefits 3 Other, net (5 ) Total increase in O&M expenses $ 52
Nuclear cost increases are related to the amortization of prior outages and initiatives designed to improve the operational efficiencies of the plants; and
Electric and gas distribution expenses were primarily driven by increased maintenance activities due to outages, storms and vegetation management.
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Conservation Program Expenses - Conservation program expenses decreased $8.8 million, or 11.2 percent, for the nine months ended Sept. 30, 2013 compared with the same period in 2012. The decreased expense is primarily attributable to the timing of recovery of electric conservation program expenses partially offset by higher gas and electric rates used to recover program expenses. Conservation program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.
Depreciation and Amortization - Depreciation and amortization expense decreased $2.7 million, or 0.9 percent, for the nine months ended Sept. 30, 2013 compared with the same period in 2012. NSP-Minnesota reduced depreciation expense by $24 million in the third quarter of 2013 to reflect the final rate order received for the 2013 Minnesota electric rate case. This reduction was offset by increased depreciation related to normal system expansion.
Taxes (Other Than Income Taxes) - Taxes (other than income taxes) increased $7.2 million, or 4.8 percent, for the nine months ended Sept. 30, 2013 compared with the same period in 2012. The increase is due to higher property taxes primarily in Minnesota.
Allowance for Funds Used During Construction, Equity and Debt (AFUDC) - AFUDC increased $4.1 million for the nine months ended Sept. 30, 2013 compared with the same period in 2012. The increase is primarily due to the expansion of transmission facilities and other capital expenditures.
Interest Charges - Interest charges decreased $14.6 million, or 9.3 percent, for the nine months ended Sept. 30, 2013 compared with the same period in 2012. The decrease is primarily due to refinancings at lower interest rates. This is partially offset by higher long-term debt levels and $3 million of interest associated with customer refunds in Minnesota based on the final rate order received for the 2013 Minnesota electric rate case.
Income Taxes - Income tax expense increased $10.0 million for the nine months ended Sept. 30, 2013 compared with the same period in 2012. The increase in income tax expense was primarily due to higher pretax earnings in 2013 and a discrete tax benefit of approximately $15.0 million for a carryback in 2012. These were partially offset by recognition of research and experimentation credits in 2013, decreased state income taxes in 2013, and a tax benefit for a carryback claim related to 2013. The ETR was 31.1 percent for the nine months ended Sept. 30, 2013 compared with 33.8 percent for the same period in 2012. The lower ETR for 2013 was primarily due a tax benefit for a carryback claim related to 2013 and research and experimentation credits in 2013. These were partially offset by the carryback adjustment in 2012.
Public Utility Regulation
Minnesota 2014 Multi-Year Electric Rate Case - In November 2013, NSP-Minnesota expects to file a multi-year rate plan for its Minnesota retail electric jurisdiction. The case will be based on a 2014 FTY and will include a request for incremental rate recovery for certain capital related costs in 2015. The case is driven by substantial investment in the system - including the replacement of the steam generator at Prairie Island; the life extension at the nuclear plants, the return to service of Sherco Unit 3 and additional owned wind generation. The rate case also will reflect higher property taxes and other general business costs. Interim rates, subject to refund, are expected to take effect in January 2014. NSP-Minnesota also anticipates introducing a mitigation plan, as part of the rate case, to lessen the impact on the customer bill. NSP-Minnesota's mitigation plan could include further accelerating a theoretical depreciation reserve and/or utilizing expected Department of Energy refunds in excess of amounts needed to fund its decommissioning expense.
Minnesota Resource Plan - In March 2013, the MPUC approved NSP-Minnesota's 2011-2025 Resource Plan and ordered a competitive acquisition process be conducted with the goal of adding approximately 500 megawatts (MW) of generation to the NSP System by 2019. Bid proposals were received in April 2013.
In September 2013, NSP-Minnesota submitted testimony to the MPUC and recommended a self-build, 215 MW natural gas combustion turbine at the Black Dog site and either Calpine's Mankato combined cycle natural gas project or Invenergy's Cannon Falls combustion turbine natural gas project. Hearings were held in October 2013. The competitive acquisition schedule is expected to be as follows:
ALJ report due Dec. 31, 2013; and