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| NWE > SEC Filings for NWE > Form 10-Q on 24-Jul-2012 | All Recent SEC Filings |
24-Jul-2012
Quarterly Report
OVERVIEW
NorthWestern Corporation, doing business as Northwestern Energy, provides electricity and natural gas to approximately 668,300 customers in Montana, South Dakota and Nebraska. For a discussion of NorthWestern's business strategy, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2011.
Significant achievements during the three months ended June 30, 2012 include:
• Entered into an Equity Distribution Agreement with UBS Securities LLC. Under this agreement we sold 687,285 shares of common stock at an average price of $35.40 per share; and
• Priced $90 million of First Mortgage Bonds at 4.15% and $60 million of First Mortgage Bonds at 4.30%, which are expected to be issued in August 2012.
Strategy Update
Mountain States Transmission Intertie Project (MSTI)
The MSTI line is a proposed 500 kV transmission project from southwestern Montana to southeastern Idaho with a potential capacity of 1,500 MWs. We reported in our annual report on Form 10-K for the year ended December 31, 2011 that there is significant market uncertainty related to the project. California is the largest potential market that could be served by renewable (primarily wind) generation from Montana. However, California may ultimately implement restrictions limiting the ability to use out-of-state resources to meet its renewable portfolio standards. In addition, there are other proposed competing projects to MSTI that may ultimately be able to provide more cost effective transmission to end users.
In January 2012, we signed a Memorandum of Understanding (MOU) with the Bonneville Power Administration (BPA) agreeing to explore the potential for MSTI to accommodate its needs. The MOU provides that by July 31, 2012, the parties will seek to complete economic and engineering viability studies and a capacity and cost allocation methodology that considers other partners in the line and treatment for unsubscribed capacity and cost. The outcome of these studies will provide information necessary for BPA and us to determine whether or not to consider future agreements for participation in MSTI. We are currently evaluating options with BPA and we expect BPA to notify us of its intent to participate in MSTI by September 30, 2012. The viability of some of these options is also likely dependent on our ability to obtain other customers.
We also reported in our annual report on Form 10-K for the year ended December 31, 2011 that we received a favorable Montana Supreme Court ruling on siting issues and we expected the Montana Department of Environmental Quality (MDEQ) to issue a draft environmental impact statement (EIS) by August 31, 2012, a final EIS by September 30, 2013, a Record of Decision by December 31, 2013, and a Notice to Proceed by third quarter 2014. On May 30, 2012, the Idaho Bureau of Land Management issued a decision which ultimately led to a letter dated June 25, 2012 from the BLM acting in its role as a lead agency on MSTI permitting requiring additional MSTI route alternatives be developed and studied in detail to avoid core sage grouse habitat. This ruling is expected to delay the EIS timeline described above by a minimum of six to nine months; however, the BLM and the MDEQ have not provided us with a fully updated schedule at this time. Such a delay in the timeline would also result in increased costs and delay the anticipated construction timeline, which would impact the ability of MSTI to be available for potential market participants and provides uncertainty for market participants relying on production tax credits as a part of their development strategy. Based on these developments, if the project proceeds, we currently estimate the project would be completed in late 2018. Due to the lack of clarity around the key market participants and permitting issues noted above, we have indefinitely extended the open season process for MSTI.
Due to the uncertainty surrounding the project, certain aspects are scalable and thus can be built out to more closely match the timing and needs of new generation and loads. To avoid excessive risk for us, it is critical to reduce regulatory uncertainty before beginning construction and making large capital investments and/or commitments. We have been contemplating a strategic partner to own up to 50% of MSTI, however there can be no assurance that we will enter into such a partnership. Through June 30, 2012, we have capitalized approximately $23.5 million of preliminary survey and investigative costs associated with the MSTI transmission project. Due to the continued market uncertainty and permitting issues related to the sage grouse causing a delay in the EIS timeline, we are currently evaluating our decision to continue pursuing MSTI. If we determine an agreement with BPA is unlikely, or cannot be completed on a timely basis, we may abandon the project. If we abandon our efforts to pursue MSTI, we may have to write-off all or a portion of these costs, which could have a material
adverse effect on our results of operations.
Dave Gates Generating Station at Mill Creek (DGGS)
Our regulatory filings seeking approval of rates related to DGGS are based on approximately 80% of our revenues related to the facility being subject to the jurisdiction of the Montana Public Service Commission (MPSC) and approximately 20% being subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). In March 2012, the MPSC issued a final order in review of our previously submitted required compliance filing. The MPSC found that the total project costs incurred were prudent and established final rates. As a result of the lower than estimated construction costs and impact of the flow-through of accelerated state tax depreciation, the final rates are lower than our 2011 interim rates. We are refunding the amount we over collected of approximately $6.2 million to customers over a one-year period beginning in May 2012. The MPSC's final order approves using our proposed cost allocation methodology on a temporary basis, and requires us to complete a study of the relative contribution of retail and wholesale customers to regulation capacity needs. The results of this study may be used in determining future cost allocations between retail and wholesale customers.
A FERC hearing regarding DGGS rates, including our proposed allocation methodology which has been challenged by intervenors, was held in June 2012 and an initial decision is scheduled to be issued in September 2012. In response to the initial decision, we and the intervening parties will have the opportunity to respond with briefs in support or opposition. Following these briefs the FERC is expected to take up the record and issue a binding decision, which we currently expect during the second quarter of 2013. We continue to bill customers interim rates which have been effective since January 1, 2011. These interim rates are subject to refund plus interest pending final resolution at FERC.
Through June 30, 2012, we have deferred revenue of approximately $2.7 million associated with DGGS due to lower than estimated construction costs, our current estimate of operating expenses as compared to amounts included in our interim rate requests, and uncertainty related to the FERC's ultimate treatment of our cost allocation methodology. This uncertainty could result in an inability to fully recover our costs, as well as requiring us to refund more interim revenues than our current estimate.
DGGS, which began commercial operation on January 1, 2011, was shut down on January 31, 2012 after problems were discovered in the power turbines of two of the generation units. Similar problems were subsequently found in the third unit. There are two power turbines per unit, and as of June 30, 2012 five of the six turbines have been returned to service through using a combination of the original turbines after servicing by their supplier Pratt & Whitney Power Systems (PWPS) and turbines on loan from PWPS. We are coordinating with PWPS to investigate the root cause of the problem, which is expected to take several months. When the root cause of the problem is determined, the units may require modification or further service. However, in that event, we anticipate that work will be performed in a manner that will not require DGGS to be taken completely off-line. We expect the turbine repair costs will be covered under the manufacturer's warranty. Between February and April, we acquired regulation service from third parties, which resulted in incremental costs of approximately $1.4 million, as compared to fully operating DGGS. We believe the incremental contracted costs for regulation service should be recoverable from customers through our normal course of business; however, there can be no assurance that the MPSC and/or FERC will allow us full recovery of such costs.
RESULTS OF OPERATIONS
Our consolidated results include the results of our reportable business segments, which are primarily engaged in the electric and natural gas business. The overall consolidated discussion is followed by a detailed discussion of gross margin by segment.
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Gross Margin, that is considered a "non-GAAP financial measure." Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross Margin (Revenues less Cost of Sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of Gross Margin is intended to supplement investors' understanding of our operating performance. Gross Margin is used by us to determine whether we are collecting the appropriate amount of energy costs from customers to allow recovery of operating costs. Our Gross Margin measure may not be comparable to other companies' Gross Margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.
Factors Affecting Results of Operations
Our revenues may fluctuate substantially with changes in supply costs, which are generally collected in rates from customers. In addition, various regulatory agencies approve the prices for electric and natural gas utility service within their respective jurisdictions and regulate our ability to recover costs from customers.
Revenues are also impacted to a lesser extent by customer growth and usage, the latter of which is primarily affected by weather. Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers. We measure this effect using degree-days, which is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Heating degree-days result when the average daily temperature is less than the baseline. Cooling degree-days result when the average daily temperature is greater than the baseline. The statistical weather information in our regulated segments represents a comparison of this data.
OVERALL CONSOLIDATED RESULTS
Three Months Ended June 30, 2012 Compared with the Three Months Ended June 30,
2011
Three Months Ended June 30,
2012 2011 Change % Change
(dollars in millions)
Operating Revenues
Electric $ 196.2 $ 186.8 $ 9.4 5.0 %
Natural Gas 48.1 64.7 (16.6 ) (25.7 )
Other 0.3 0.3 - -
$ 244.6 $ 251.8 $ (7.2 ) (2.9 )%
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Three Months Ended June 30,
2012 2011 Change % Change
(dollars in millions)
Cost of Sales
Electric $ 78.1 $ 76.9 $ 1.2 1.6 %
Natural Gas 18.3 33.5 (15.2 ) (45.4 )
$ 96.4 $ 110.4 $ (14.0 ) (12.7 )%
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Three Months Ended June 30,
2012 2011 Change % Change
(dollars in millions)
Gross Margin
Electric $ 118.1 $ 109.9 $ 8.2 7.5 %
Natural Gas 29.8 31.2 (1.4 ) (4.5 )
Other 0.3 0.3 - -
$ 148.2 $ 141.4 $ 6.8 4.8 %
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Primary components of the change in gross margin include the following:
Gross Margin
2012 vs. 2011
(in millions)
Demand-side management (DSM) lost revenues $ 4.5
Montana property tax tracker 2.3
Transmission capacity 1.1
DGGS 0.5
South Dakota natural gas rate increase 0.4
Operating expenses recovered in trackers 0.2
Natural gas retail volumes (2.4 )
Other 0.2
Increase in Consolidated Gross Margin $ 6.8
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This $6.8 million increase in gross margin includes the following:
• An increase in DSM lost revenues recovered through our electric supply
tracker related to our DSM efficiency programs, as described further
below;
• An increase in Montana property taxes included in a tracker as compared to the same period in 2011;
• An increase in transmission capacity revenues due to higher demand to transmit energy for others across our lines;
• Higher DGGS related revenues due to the regulatory treatment of bonus depreciation;
• An increase in South Dakota natural gas rates due to a rate case settlement in 2011; and
• Higher revenues for operating expenses recovered in trackers, primarily related to customer efficiency programs and environmental remediation costs.
These increases were partly offset by a decrease in natural gas retail volumes due primarily to warmer spring weather reducing our customer usage for heating during the second quarter.
Demand-side Management (DSM) lost revenues - Base rates, including impacts of past DSM activities, are reset in general rate case filings. As time passes between rate cases, more energy saving measures (primarily more efficient residential and commercial lighting) are implemented, causing an increase in DSM lost revenues. During the second quarter of 2012 we recognized approximately $6.6 million of DSM lost revenues as compared with approximately $2.1 million during the second quarter of 2011. The 2012 amount includes $3.3 million in DSM lost revenues for the July 2010 through June 2011 tracker period, which we recognized as revenue when we received MPSC approval in April 2012.
Historically, the MPSC has authorized us to include a calculation of lost revenues based on actual historic DSM program activity, but prohibited the inclusion of forecasted or estimated future lost revenue. In its April 2012 order, the MPSC authorized us to include forecasted lost revenues in future tracker filings. Based on this order, we have recognized $3.3 million of the requested $5.7 million of lost revenues for the 2011/2012 tracker period. We have not recognized the entire amount as we are required to provide the MPSC with a detailed independent study supporting our requested DSM lost revenues during the fourth quarter of 2012. At this time, we cannot anticipate the results of the study. If it supports our request, we may be able to recognize an additional $2.4 million of lost revenues. Alternatively, the study could indicate that our requested amounts are too high and we may have to refund a portion of DSM lost revenues that we have recognized for the latest tracker period. We do not expect the MPSC to issue a final order related to the 2011/2012 DSM lost revenues until at least the first quarter of 2013.
Three Months Ended June 30,
2012 2011 Change % Change
(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative $ 67.1 $ 69.5 $ (2.4 ) (3.5 )%
Property and other taxes 25.9 20.6 5.3 25.7
Depreciation 26.4 25.1 1.3 5.2
$ 119.4 $ 115.2 $ 4.2 3.6 %
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Consolidated operating, general and administrative expenses were $67.1 million
for the three months ended June 30, 2012, as compared with $69.5 million for the
three months ended June 30, 2011. Primary components of the change include the
following:
Operating, General &
Administrative Expenses
2012 vs. 2011
(in millions)
Bad debt expense $ (1.3 )
Operating and maintenance (0.6 )
Plant operator costs (0.5 )
Operating expenses recovered in trackers 0.2
Other (0.2 )
Decrease in Operating, General & Administrative Expenses $ (2.4 )
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The decrease in operating, general and administrative expenses of $2.4 million was primarily due to lower bad debt expense based on higher collections from customers, a timing related decrease in proactive line maintenance and tree trimming as more time was spent on capital projects as compared to the same period in 2011, and lower plant operator costs at Colstrip Unit 4 offset in part by higher plant operator costs at Big Stone and Coyote due to the timing of scheduled maintenance. These decreases were partly offset by higher operating expenses primarily related to costs incurred for customer efficiency programs and environmental remediation costs, which are recovered from customers through trackers and have no impact on operating income.
Property and other taxes was $25.9 million for the three months ended June 30, 2012, as compared with $20.6 million in the second quarter of 2011. This increase was due to higher assessed property valuations in Montana and plant additions. The higher assessed property valuations are primarily due to a lower capitalization rate used by the Montana Department of Revenue. We estimate property taxes throughout each year and update to the actual expense when we receive our Montana property tax bills in November.
Depreciation expense was $26.4 million for the three months ended June 30, 2012, as compared with $25.1 million in the second quarter of 2011. This increase was primarily due to plant additions.
Consolidated operating income for the three months ended June 30, 2012 was $28.7 million, as compared with $26.2 million in the second quarter of 2011. This increase was primarily due to an increase in gross margin offset in part by higher operating expenses as discussed above.
Consolidated interest expense for the three months ended June 30, 2012 was $15.9 million, as compared with $16.9 million in the second quarter of 2011. This decrease was primarily due to lower interest rates on debt outstanding and higher capitalization of allowance for funds used during construction.
Consolidated other income for the three months ended June 30, 2012, was $1.2 million, as compared with $1.1 million in the second quarter of 2011.
Consolidated income tax expense for the three months ended June 30, 2012 was $2.6 million, as compared with an income tax benefit of $0.5 million in the same period of 2011. Our effective tax rate was 18.3% for the three months ended June 30, 2012 as compared with (4.9)% for the three months ended June 30, 2011. The following table summarizes the significant differences from the federal statutory rate, which resulted in reduced income tax expense (in thousands):
Three Months Ended June 30,
2012 2011
Income Before Income Taxes 14.0 10.5
Income tax calculated at 35% federal statutory rate (4.9 ) (3.7 )
Permanent or flow through adjustments:
Flow-through repairs deductions 2.2 1.5
Flow-through of state bonus depreciation deduction 0.5 0.7
Recognition of state net operating loss
benefit/valuation allowance release - 1.6
State income tax and other, net (0.4 ) 0.4
2.3 4.2
Income tax (expense) benefit (2.6 ) 0.5
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Our effective tax rate differs from the federal statutory tax rate of 35% primarily due to the regulatory impact of flowing through federal and state tax benefits of repairs deductions and state tax benefit of bonus depreciation deductions. The regulatory accounting treatment of these deductions requires immediate income recognition for temporary tax differences of this type, which is referred to as the flow-through method. When the flow-through method of accounting for temporary differences is reflected in regulated revenues, we record deferred income taxes and establish related regulatory assets and liabilities.
Consolidated net income for the three months ended June 30, 2012 was $11.4 million as compared with $11.0 million for the same period in 2011. This increase was primarily due to higher operating income and lower interest expense partly offset by higher income tax expense as discussed above.
Six Months Ended June 30, 2012 Compared with the Six Months Ended June 30, 2011
Six Months Ended June 30,
2012 2011 Change % Change
(dollars in millions)
Operating Revenues
Electric $ 403.2 $ 395.4 $ 7.8 2.0 %
Natural Gas 149.9 193.9 (44.0 ) (22.7 )
Other 0.6 0.8 (0.2 ) (25.0 )
$ 553.7 $ 590.1 $ (36.4 ) (6.2 )%
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Six Months Ended June 30,
2012 2011 Change % Change
(dollars in millions)
Cost of Sales
Electric $ 161.1 $ 161.4 $ (0.3 ) (0.2 )%
Natural Gas 73.7 111.1 (37.4 ) (33.7 )
$ 234.8 $ 272.5 $ (37.7 ) (13.8 )%
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Six Months Ended June 30,
2012 2011 Change % Change
(dollars in millions)
Gross Margin
Electric $ 242.1 $ 234.0 $ 8.1 3.5 %
Natural Gas 76.2 82.8 (6.6 ) (8.0 )
Other 0.6 0.8 (0.2 ) (25.0 )
$ 318.9 $ 317.6 $ 1.3 0.4 %
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Primary components of the change in gross margin include the following:
Gross Margin
2012 vs. 2011
(in millions)
DGGS $ 5.0
DSM lost revenues 4.5
Transmission capacity 1.3
Montana property tax tracker 1.0
South Dakota natural gas rate increase 1.0
Electric and natural gas retail volumes (10.2 )
Gas production (0.8 )
Other (0.5 )
Increase in Consolidated Gross Margin $ 1.3
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This $1.3 million increase in gross margin includes the following:
• Higher DGGS related revenues, including approximately $2.7 million that we
had deferred in prior periods pending outcome of allocation uncertainty in
Montana;
• An increase in DSM lost revenues recovered through our supply tracker related to efficiency measures implemented by customers;
• An increase in transmission capacity revenues due to higher demand to transmit energy for others across our lines;
• An increase in Montana property taxes included in a tracker as compared to the same period in 2011; and
• An increase in South Dakota natural gas rates.
These increases were partly offset by the following:
• A decrease in electric and natural gas retail volumes due primarily to
warmer winter and spring weather; and
• A decrease in Battle Creek gas production margin from lower market prices.
Six Months Ended June 30,
2012 2011 Change % Change
(dollars in millions)
Operating Expenses (excluding cost of sales)
Operating, general and administrative $ 132.7 $ 136.9 $ (4.2 ) (3.1 )%
Property and other taxes 49.6 45.9 3.7 8.1
Depreciation 52.9 50.4 2.5 5.0
$ 235.2 $ 233.2 $ 2.0 0.9 %
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Consolidated operating, general and administrative expenses were $132.7 million
for the six months ended June 30, 2012, as compared with $136.9 million for the
six months ended June 30, 2011. Primary components of the change include the
following:
Operating, General &
Administrative Expenses
. . .
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