NorthWestern Energy Group Inc (NWE) 2010 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the NorthWestern Corporation year-end 2010 financial results conference call. At this time, all participants are in a listen-only mode.

(Operator Instructions)

I would now like to turn the conference over to our host, Mr. Dan Rausch.

All right, thanks. Good afternoon and welcome to NorthWestern Corporation's December 31, 2010, year-end financial results conference call webcast. Our results have been released and the release is available on our website at www.NorthWesternernergy.com. And we also filed our 10-K after the market closed yesterday.

Joining us today on the call are Bob Rowe, President and CEO; Brian Bird, Chief Financial Officer; Dave Gates, Vice President of Wholesale Operations; Kendall Kliewer, Controller; and Heather Grahame, General Counsel.

I'll now quickly read the Safe Harbor statement. This presentation contains forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements are based upon our current expectations and speaks only as of this date.

Our actual results may differ materially and adversely from those expressed in our forward-looking statements as a result of various factors and uncertainties, including those listed on the annual report of Form 10-K, recent forthcoming 10-Qs, recent Form 8-Ks and other filings with the SEC.

We undertake no obligation to revise or publicly update our forward-looking statements for any reason.

Following our presentation, those joining us by teleconference will be able to ask questions. A replay of today's call will be available beginning at 5.00 Eastern time today through March 11, 2011. To access the replay, dial 800-475-6701 and then access code 189762. Number again, 800-475-6701 and code 189762.

A replay of today's webcast will also be available on our website. And with that, I'll turn it over to President and CEO, Bob Rowe.

Thank you. It's been a good year, 2010, as we focused on what we do best -- investing and service for our customers and providing value for our shareholders. Net income improve $77.4 million for 2010, compared with $73.4 million in 2009.

In addition, the Company's Board of Directors declared a common stock dividend of $0.36 per share, payable on March 31, 2011, to common shareholders of record as of March 15. This will keep our dividend within what we consider our sustainable payout range of 60% to 70% of net income.

In December, we received a final order from the Montana Public Service Commission, the MPSC, approving an increase in base electric rates of $6.4 million.

The final order included modifications applicable to the electric utilities, revenue requirement and a requirement to implement a modified lost revenue adjustment mechanism, which was proposed in the docket as a decoupling mechanism. An inclining block rate structure and a reduction to the authorized return on equity for the electric utility from 10.25% to 10%.

NorthWestern and other parties to the case are appealing the required implementation of the modified lost revenue adjustment mechanism, the block rate and the ROE reduction.

In addition, we made progress on our strategy to secure more control on supply to serve our customers. In pursuit of that, we completed the Mill Creek Generation Station, a $183 million,150-megawatt natural gas-fired regulating reserve power plant. That came into commercial operation on January 1.

We recently signed memoranda of understanding to develop two wind projects in central Montana, totaling 48 megawatts, and we purchased a majority interest in the Battle Creek Natural Gas Field and the Sweet Grass Arch in Blaine County, Montana, which we refer to as the Battle Creek field. And that was for a total of $12.4 million.

During the year, we were also acknowledged for our performance by various parties. In April, Standard & Poors added NorthWestern to its small cap 600 group of stocks. That occurred, again, April of last year.

In December, we were recognized by PA Consulting Group as the recipient of the 2010 Service One award for outstanding customer care performance. And this was for the sixth year out of the last seven.

The Service One award is given annually to recognize utilities for their excellence in providing exceptional customer service.

Also, Forbes.com named NorthWestern Energy as one of its top 100 most trustworthy companies in America.

And in January of this year, Moody's Investor Service upgraded our senior secured debt from A3 to A2 and our senior secured bank credit facility from Baa2 to Baa1.

Now let me turn it over to Brian to discuss our 2010 financial results in more detail. Brian?

Thanks, Bob. As Bob said earlier, we reported net income of $77.4 million or diluted EPS of $2.14 a share during 2010, compared to net income of $73.4 million or $2.02 a share in 2009.

Our earnings increased $0.12 per diluted share or 5.9%. So we had a nice improvement year-over-year.

We had a table provided with the press release which gives a full reconciliation of that improvement. But at a high level, I would like to discuss the $4 million improvement to net income with the following. First, gross margin improved $11.4 million year-over-year, primarily due to an increase in property taxes recovered in our tracker; our interim rate increase and improvements in our electric transmission and distribution businesses.

Second, our operating general and administrative expenses were down significantly, which totally offset an increase in property taxes and which kept those overall costs flat and allowed our EBITDA to be the same as our margin improvement of an increase of $11.4 million.

For total operating expenses, depreciation was higher by $2.8 million year-over-year resulting in an overall improvement in operating income of approximately $8.6 million.

Third, we had lower interest expense and higher other income, which provided a net benefit year-over-year of $5.7 million primarily due to higher AFUDC from the construction of Mill Creek.

And this, along with operating income benefit mentioned above resulted in a pretax income improvement year-over-year of $14.4 million.

And finally, these three favorable variances were partially offset by higher tax expenses year-over-year of approximately $10.5 million, primarily due to higher pretax income. And, if you remember, we had a significant repairs tax deduction benefit recognized in 2009.

For the fourth quarter, we had consolidated net income of $22.6 million or $0.63 per share, compared with $25.6 million or $0.70 a share for the fourth quarter of 2009.

The decrease was primarily due to an increase in operating expenses partially offset by an increase in gross margin.

Consolidated operating expenses increased in the fourth quarter approximately $6.3 million, primarily due to increased property taxes in Montana.

Consolidated gross margin increased in the fourth quarter approximately $2.5 million, primarily due to the increase in Montana property taxes recovered in a tracker and an increase in Montana electric transmission and distribution rates, partially offset by warmer winter weather in our service territories.

Now let me take some time to talk about our 2011 earnings outlook. Our estimate for fully diluted earnings per share in 2011 is a range of $2.25 to $2.40 per fully diluted share.

The major drivers of earnings from 2011 to -- 2010 to 2011 include adding the Mill Creek Generation Station to rate base and the associated earnings.

Also a full-year effect of the increase related to our Montana transmission and distribution electric rates. Also the expiration of a power sales agreement associated with our ownership in Colstrip Unit 4.

We have also seen increased electric and natural gas volumes, including Montana transmission volumes due to an assumption of some additional economic recovery in 2011.

Our Battle Creek Field will contribute for a full year in 2011. And finally, we expect a small tax benefit from the additional bonus tax depreciation related to the Small Business Jobs act of 2010.

Offsetting these three -- offsetting these positive drivers for 2011, are negative drivers, including we expect labor and other operating expenses to increase in 2011, compared with 2010.

We will be experiencing some scheduled maintenance at the Big Stone Plant in South Dakota in 2011, decreasing output and revenues. And finally, we expect an increase in property taxes and depreciation expense in 2011, as we continue to increase our capital investment.

Other primary assumptions included in our 2011 guidance, our fully diluted average shares outstanding will be about $36.4 million.

We expect our effective tax rate to be between 20% and 24%. And we expect normal weather in the Company's electric and natural gas service territories for 2011.

Now let me move us to -- our attention to the balance sheet. At year-end, we had total liquidity of approximately $103 million with cash of $6 million and $97 million available from our corporate revolver.

The total debt at December 31, 2010, was approximately $1.1 billion, compared with $987 million at December 31, 2009.

The Company had a long-term debt-to-total capitalization ratio of approximately 56.6% at December 31, 2010, and as we note in our 10-K, we plan to maintain a 50% to 55% debt-to-total capital ratio on a going-forward basis.

During 2011, we expect to move back into that range as our operating cash flows are expected to remain strong. Cash provided by operating activities totaled $219 million for the year ended December 31, 2010, as compared with $117 million during year-end December 31, 2009.

This increase in operating cash flows is primarily related to a decrease in pension funding of $81 million as compared with 2009. And also in 2009, included a payment of an [Amensen] verdict of approximately $27 million. That, of course, did not occur in 2010.

As you can see, our balance sheet and cash flows remain strong.

I would also like to address the bonus tax depreciations effect on our business. The Small Business Jobs Act of 2010 was signed into law extending bonus appreciation for 2010 through 2012, and increased the bonus rate from 50% to 100% for costs incurred from September 8, 2010, through 12/31 of 2011.

Essentially, any capital project that is placed in service on September 8, 2010, through 12/31, 2011, will be deducted for tax at 100% bonus depreciation as it relates to costs incurred from that same period in the year the project is placed in service.

Therefore, it's possible that some of the project's cost will qualify for 50% bonus tax depreciation while other costs may qualify for 100% bonus tax depreciation.

For us, the most significant capital project in 2010 was the Mill Creek Generation Station. In Montana, the bonus depreciation deduction for determining state income taxes is subject to the flow-through methodology for setting customer rates in Montana.

As rates associated with Mill Creek will be determined during 2011, the lower taxes attributed to bonus depreciation are flowed through two customers in revenue requirements.

Since we have large NOL carry-forwards and aren't making current cash payments for income taxes, the current impact to us is minimal.

The extension of bonus appreciation will increase our NOL carry-forwards extending the time before we start paying cash taxes, and it will provide benefits to our customers in the form of lower rates related to Mill Creek.

We expect our cash payments for income taxes will be minimal through at least 2015, based on our projected taxable income and anticipated use of consolidated NOL carry-forwards that total about $434 million at December 31, 2010.

Now I'd like to take a step back and list a couple of accomplishments the Company has achieved over the last five years.

First, our credit ratings have improved significantly and now our secured debt ratings are in the single A category .

Our improved credit metrics have occurred because of positive regulatory outcomes and improved financial performance.

Our net earnings have grown from about $60 million in 2005 to this year's $77 million in net income for a compound average growth rate of about 4.5% annually.

Accordingly, our earnings per share have grown from $1.65 in 2005 to this year's $2.14 per share. This growth has occurred without any issuance of equity and, in fact, we had a share buy-back a couple years ago.

Our operating cash flows improved from about $150 million in 2005, to this year's $218 million. We have increased our dividend from $1 in 2005 to now an annualized dividend of $1.44 in 2011, based on our first quarter dividend, which equates to a compound average growth rate of 6.2%.

And finally, our rate base has increased from about $1.2 billion then to our current level of approximately $1.8 billion. Most of that increase has occurred in the state of Montana with the purchase of the previously leased Colstrip Unit 4 interest and the completion of construction of the Mill Creek Generation Station.

As a result, we are proud of our accomplishments these past five years and are excited by our prospects going forward. With that, now let me turn it back to

Thank you, Brian, for that good report. As I continue with the outlook for the year, I will start with the regulatory update for Montana.

As I mentioned in December of '10, the Montana Commission issued a final order approving our revenue requirement portion of the rate filing with an additional requirement to [implified] a modified loss revenue adjustment mechanism which had been proposed in the case as a decoupling mechanism along with an inclining block rate structure for electric energy customers.

Very importantly, as part of the case, we were able to reach a transparent revenue requirements stipulation with the Montana Consumer Council and with the large group customer group representing industrial customers. And we reached a separate allocated cost-of-service stipulation with those parties and with the parties representing lower-income customers.

Both of these stipulations were approved on four to one votes by the Montana Commissions.

The concerns raised by parties and the challenges have dealt with the rate design, specifically decoupling and the inverted rate structure.

Some key provisions of the Commission's final order include an increase in base electric rates of $6.4 million;, a decrease in base natural gas rates of approximately $1 million; and an authorized return on equity of $10.25 for the gas utility and $10.00 for the electric utility.

And recall that the revenue requirement stipulation had specified a $10.25 ROE for both gas and electric, but did reserve the Consumer Council's right to argue for a lower ROE if decoupling was adopted along with our right to oppose a lower ROE associated with decoupling. In fact, we made it very clear to the Commission at the hearing in our briefs that because we already had a lost revenue adjustment mechanism or LRAM, we strongly opposed decoupling, if it included an ROE below the $10.25 stipulated.

The overall authorized rates of return are based on the equity percentages above, plus long-term debt cost of 5.76% and a capital structure of 52% debt and 48% equity.

We appealed the Commission's -- the specific portions of the Commission's decision to a Montana District Court and that concerned the reduction -- from our perspective, the reduction on return on equity associated with the coupling on the electric side. And, in addition, as I go forward, individual members of the Commission have continued to discuss other potential modifications to the final order.

We can't, at this point, predict what the ultimate outcome of the disputed issues will be. I can say that we're working closely with the other two parties that had appealed the specific portions of the Montana Commission's decision. And we presented what we think is a very constructive proposed resolution which would address all of the concerns and that proposed resolution is fully supported by the other two parties who appealed.

We'll continue to support the stipulations and try to close out these remaining issues.

Now, I'll provide you with an update on some of our potential investments and service in our service territory.

I'll start with our distribution system infrastructure plan, which we call the DSIP, and this is a plan for significant, we believe, necessary investment in our gas and electric distribution systems, specifically in Montana.

As part of our commitment to maintain high levels of reliability and safety, and just a performance, we continue to evaluate the condition of our distribution assets to address aging infrastructure, capacity, reliability and safety. And this occurs through our asset management process within distribution.

Additionally, we formed an infrastructure stakeholder group to assist us as we consider possible future scenarios for investment in our distribution systems and evaluate potential impacts of these different scenarios on rates and future service quality.

So based on our analysis, our work with the infrastructure stakeholder group and our assessments, if necessary, proactive maintenance to our system. We're currently projecting capital expenditures for this infrastructure investment to be approximately $287 million over a seven-year time span beginning in 2011. And importantly these amounts are in addition to our base budget.

About 80% of the capital spend would be related to our electric system and about 20% to our natural gas system. This is a challenge that utilities around the country are addressing in various means.

Some states have future test years where rates are set based on known expenses in the upcoming year. Montana uses an historic test year and indeed, as you know, the rate case that we're concluding was based on a 2008 test year with modifications for 2009.

So, we're proposing a specific method to cover the expenses associated with the DSIP, the distribution system plan.

We submitted a request for an accounting order to the Montana Commission in January to allow us to defer and amortize incremental operating and maintenance expenses for 2011 and 2012 over a five-year period to begin in 2013. This is very similar to what we did with the $93 million pension expenditure in late 2009. That was a great success. A request does not cover capital but only the expense items which might otherwise be lost.

During the second quarter of this year, we plan to submit a formal proposal to the Commission requesting approval of the project in form and substance in advance of its full implementation and including recovery of the 2011 and 2012 expenses, as well as special cost recovery treatment for the incremental capital expenditures and expenses related to the project from 2011 to 2017.

You can think of this as a two-year ramp-up or phase-in followed by five years of full implementation.

In addition, I'd like to discuss some of our supply-side investments. First Mill Creek. We've been discussing our needs to regulate and provide momentary balancing of our electric supply load for some time now and this really is a great example of our strategy to own our own supply resources and provide greater control over the system and long-term price stability for our customers.

So we were delighted to be able to report that on December 31, we completed construction of Mill Creek. As many of you know, that's a 150-megawatt natural gas-fired facility.

It was placed in service and achieved commercial operation on January 1, accompanied by fireworks.

We received an interim order from the FERC in October and from the Montana Commission in November of last year approving rates based on the estimated construction costs. And those rates became effective beginning January 1, and are, of course, subject to refund and to be replaced by the current contract costs for ancillary services.

The plant came in on time. It came in under budget and is performing exactly as planned. Indeed, our transmission engineers had a presentation to our Board this morning explaining that the plant is producing -- is performing even better than expected.

As you heard Brian state, Mill Creek will be a significant contributor to our earnings starting in 2011.

With respect to renewable electric supply, as I mentioned, we have signed a memoranda of understanding with two wind developers that would provide a total of about 48 megawatts.

These are in Montana. The supply cost will be less than the qualifying facility costs, also referred to as our avoided cost. And this was a good outcome for our customers.

And we expect to execute definitive agreements during the first quarter of the year and we'll seek regulatory preapproval as is available in Montana during 2011 to place the projects into rate base.

Pending regulatory approval, we expect these wind-related capital expenditures to range between $100 million and $120 million with construction completed and service commencing by 12/31/12.

Concerning natural gas reserves, we visited about the subject on a number of calls and we have new purchased a majority interest in producing wells in a gathering system called the Battle Creek Field.

As I mentioned, annual net production attributable to the purchase is currently right around 0.55 Bcf or about 2.5% of NorthWestern's current annual consumption in Montana for retail customers.

The field is in our service territory near Havre, and it's connected to our existing natural gas system. Under the terms of the agreement, we paid the sellers a total of $12.4 million for the majority interest in Battle Creek and that included the gathering system.

In 2011, or during the next general natural gas rate case, we will prepare a filing with the Commission seeking approval to add our interest in the Battle Creek Field and the gathering system into our regulated rate base.

Importantly, in the interim, the cost of natural gas produced, including a return on our investment, will be included in our natural gas supply tracker pending completion of the specific filing with the Commission.

So, as a result of that, we are already recovering our costs and earning a return. We continue to explore investments improving natural gas reserves to be rate based for the service of our customers.

I know I said this before, but I have -- I would like to point out at every call, that we have no interest in becoming an E&P Company.

We are only interested in proven reserves at attractive pricing to give our customers long-term price stability.

Now I'll give you an update on some of the emissions reduction issues that may be -- or challenges we face in South Dakota.

The Clean Air Visibility Rule was issued by the EPA in 2005, requiring certain electric regenerating units to achieve emissions reductions from designated sources that are deemed to contribute to visibility impairment in Class One air quality areas.

We have a 23.5% interest in Big Stone. Big Stone is a 454-megawatt coal-fired power plant located in northeastern South Dakota.

The estimated expenditures for the best available retrofit technology, the BART, based on Department of Environmental and Natural Resources proposals are approximately $500 million to $550 million.

This is for Big Stone alone, with AFUDC and overheads, our share of that would be between $130 million and $150 million.

The South Dakota PUC previously allowed the recovery of the costs of environmental improvements on a timely basis.

We're doing a number of things. First, we're keeping the South Dakota Commission informed of developments as we continue our analysis. We don't like to surprise any of our regulators.

Second, given the high cost of the emissions reduction equipment, we're reviewing all alternatives to assure that we identify, working with our co-owners, the most appropriate solutions.

Similarly, in our South Dakota territory, we're the owners of coal plant Neal No. 4. Neal 4 is located in northwest Iowa. And we're investigating installing a scrubber somewhere in the 2013 to 2015 time frame.

The overall project scope would be similar to the Big Stone scrubber. Capital expenditures, though, with Neal, are currently estimated to be around $220 million.

We're only an 8.6% owner, about 55 megawatts of a 655-megawatt facility. So our capital portion is likely to be around $20 million.

Finally, in South Dakota, related to electric supply, we've informed you previously that we're doing preliminary engineering for a peaking facility near Aberdeen, South Dakota, of about 60 megawatts. This would replace an agreement that expires at the end of December 2012.

The cost of a peaker that size would be right around $60 million and it could go into service between 2013 and 2015, depending on load needs.

Turning to the transition side of the business, first in Montana, as you know, we have three transmission projects in various stages of active development.

First an upgrade to our existing 500 KV, Colstrip Transmission System. Second Montana Collector System. Third, the Mountain States Transmission Intertie or MSTI. I will take those in reverse order of timing and start with MSTI.

As we noted in past discussions, we have extended our open seasons processes related both to MSTI and to Collector to the end of this year.

The reasons for the extension include, first of all, MSTI sighting delays. As many of you know there is pending litigation with Jefferson County, Montana. Jefferson County has -- there, the primary litigants are Jefferson County and the Montana Department of Environmental Quality.

The State Department has new appealed a lower court ruling that required active consultation with the County. As a result of this litigation, the draft EIS has been delayed by between 12 and 18 months.

Currently, the draft EIS is expected to be released in the fourth quarter of 2011, and then the final EIS in the second quarter of 2012. The Record of Decision is now expected in the third quarter of 2012.

Also contributing to the delay, as we discussed, is the general state of the economy, the economic slowdown and tightening of credit for some of the developers have combined to make it more difficult for generation developers to make long-term commitments and this is clearly something we need to order to keep the project risk manageable.

And there continues to be market confusion in California. On January 13, the California PUC authorized the use of tradeable renewable energy credits, or so-called TRECs, to maximize the benefits of RPS eligible generation to California customers. And the decision provides a temporary limit on the use of these tradeable RECs to meet California RPS procurement obligations.

Under this limit, the three largest California utilities may use tradeable RECs to meet no more than 25% of their annual RPS procurement obligations.

To protect rate payers from excessive payments for Tradeable RECs in the early stages of this TRECs market, the decision imposes a transitional price cap of $50 a REC in REC-only contracts used for RPS compliance by any of the investor-owned utilities.

Both limits will expire December 31, 2013. Also there continues to be uncertainty around the direction of federal policy and legislation. For example, the extension of the production tax credits and the investment tax credits beyond 2012 is still unknown.

Concerning the Collector System -- and this would be a gathering system within Montana -- we have yet to capitalize any costs and we're expecting to spend about $2 million capital in 2011.

Our assumed capital on the first identified line of the Collector System is approximately $200 million. And the first Collector line could be operational as soon as 2015.

Related to MSTI, we've capitalized $16.7 million through December 31st of '10, and we expect to spend about $8 million in sighting and permitting costs in '11.

Construction on MSTI would start at the earliest in 2013, and MSTI could be placed in service during 2016.

Now I'll move to the first project in the queue, the proposed upgrade to the Colstrip 500 KV. The Colstrip Transmission System, CTS, owners have reached an understanding on the concepts that need to be incorporated in the Colstrip Transmission agreement and their individual tariffs to accommodate the upgrade.

The Colstrip owners are preparing a presentation for the FERC staff to facilitate a discussion on the concepts related to interconnection and transmission service requests.

The goal is to have minimal changes to the individual participants' [odes]. Also the Bonneville Power Administration, BPA, is conducting a contested rate case on the roll-in at the Montana intertie into its network rates and the termination of the exchanged provisions of the Montana intertie agreement.

The Company and the Colstrip Transmission System owners are now conducting technical studies to determine the amount of additional capacity that could be obtained through work on the system and the technical analysis system is anticipated to be completed this year.

It's assumed that the other Transmission System owners will participate in the upgrade.

Also Northwestern has exercised its option to purchase a parcel of land south of Townsend, Montana.

This is a 280 parcel where our potential new substation would be built to upgrade the Colstrip transmission line, and the substation could serve also serve as a collection point for the renewable collector system as well as the head end for MSTI.

We acquired this property in December. The total expected cost of the Colstrip Transmission System upgrade is expected to be around $125 million.

Our capital cost to the project is estimated to be around $38 million. This is assuming that all partners to the Transmission System agreement participate pro rata. We expect to spend around $1 million in planning costs associated with the Colstrip upgrade in 2007.

Commencement of construction could occur as soon as the study work is complete, and the upgrade to the system could be completed by the end of 2013.

Now, concerning transmission opportunities in and out of South Dakota, recently the FERC approved MISOs multi-value project, or MVP, cost allocation tariff filing. And this is really one of the tough nuts to crack in transmission policy.

In doing so, FERC gave MISO authority for a cost allocation tariff for certain projects that have been identified as having regional reliability capacity constraint relief and other benefits and values to the regional MISO footprint.

In essence, MISO identified MVP, multivalue projects, will cost allocate the full revenue requirement to the entire footprint of the MISO customer base.

That's very important to note that there have to be values in order to spread recovery of the costs over the region. If there aren't regional values and benefits, there is no availability of cost spreading. So this is not a cost-shifting mechanism.

This approach does greatly simplify a transmission developer's cost recovery by foregoing the need for bilateral capacity contracts between the developer and the shippers.

NorthWestern is not currently a MISO member; however, our South Dakota territory is embedded within the MISO geographic footprint.

So we continue to advance our analysis in proposing a project or projects to the MISO. And, in fact, there are several 345 KV projects in or adjacent to our service territory in which we could elect to become a joint venture participant.

So I've been talking for a long time, and I'll say the words you've all been waiting for -- in summary. We are pleased with our performance in 2010. Despite significantly higher income taxes, we increased our net income by $4 million or $0.12 a share over 2009.

In the process we completed the Mill Creek Generating Station on time and on budget. And this is a real testament to the ability of our engineers and all of our employees to successfully undertake these very complicated projects.

We recently signed memoranda of understanding to develop wind projects in Montana totalling 48 megawatts.

We purchased an interest in a natural gas field in Montana. We were added to the S&P's small cap 600. We won the Service One award for the sixth year out of seven.

Even the Packers aren't that good.

We raised the quarterly dividend to 5.9%, keeping us within our sustainable payout range and Moody's has just upgraded our debt again.

So it's been a solid five-year period for the Company and for our customers as we focus on what we do best in providing value to what really is one of the most sound regions in the country. We expect to build on this performance and to provide the same for our customers and shareholders well into the future.

With that, I will conclude the formal remarks here and open up the call for your questions. Thank you.

Our first question comes from the line of Chris Ellinghaus.

For starters, Brian, how much did the repairs tax deduction fall off relative to Q4 of '09?

'09 -- for a full year of '09 versus '10, it was a net income impact of $2 million or $0.06. Now, remember, '09 had both '08 and '09's repairs tax deductions in them.

Right.

So for '10 versus just '09 -- actually '10's repairs went up a bit. But remember, in 2009, you were dealing with two years -- 2009 and 2008.

And how about the fourth quarter specifically?

I don't think the fourth quarter was that significant, because if you remember the big issue was we made this adjustment in the third quarter of 2009. I don't have an exact number in front of me, Chris, but I don't think it was material. I think the biggest impact was September

Q3?

Yes.

Okay. Were there any special items, insurance recoveries, legal, reserve issues?

As you see in our 2010 reported GAAP and we worked that down to a comparable number to what we provided as earnings guidance, we did back out $2.8 million on a net income basis of insurance recoveries, or $0.08.

That was the major thing, and if you could allow me, Chris, just to talk about the two other changes, the reason we also backed out $1.9 million of the Montana rate adjustment we did receive in '10, is because, if you remember, we didn't include any rate increase in our original guidance.

For apples-to-apples, we backed that out as well. And then we backed out a weather adjustment, too, of $2.1 million. Actually that was an add-back, because we had negative impacts associated with weather, primarily from the fourth quarter.

Right. Okay. And lastly, given some of the things that you have got in your capital plan, particularly the distribution plan and the wind, what can you tell us about your thinking for external equity for the next couple of years?

I think, Chris, we talked about it our Analyst Day here. We're comfortable to say we don't anticipate, with our existing capital program, no need for equity in 2011. And as we mentioned, if we had some of these energy supply projects moving forward and DSP moving forward, it depends on the relative success of that before I can really speak to 2012.

Okay, great. Thanks a lot.

Thank you.

Next, we go to the line of Paul Ridzon.

I haven't scrubbed your K yet, but what's your 2011 CapEx look like?

Our 2011 CapEx, and, again, this is maintenance CapEx, Paul, which is just associated with maintaining our existing business is $140 million.

And any greater clarity on what else could be tacked on top of that?

If you look at 2011, we do expect most of the capital associated with the transmissions relatively small. We continue to spend some capital as we continue to sight and permit there, and some other capital could be spent on preparatory work, if you will, for the pollution control equipment. We don't anticipate a significant amount of investment growth capital in 2011. As we've laid out for folks in the past, 2011 is really getting some regulatory clarity on a lot of these projects.

So nothing as far as wind either, probably?

From the wind perspective, again, I think we're going through a regulatory approval process. Until that's completed, there will not be a lot spent on the wind capital.

Then in your walk from '10 to '11, you've got some outage timing. I think it's $0.06 to $0.07. How much of that is unusual, one-time issue and probably won't happen again for several years?

Paul, this is Dave Gates. Those are planned outages, turnarounds at Big Stone and then, as you know, we have a reciprocal sharing agreement with Colstrip 3 and there's an outage at that plant that's coming here.

Are those unusual outages or are these just--?

No, they would happen about every three years.

Okay.

Or four, depending on the plant operator.

(inaudible) -- getting into traction?

Say again, please?

There's been some noise in the legislature with the change in party largely being less friendly to renewables, do you think any of this has any traction?

We have been in a windowless room at an airport motel for a couple of days. But my understanding is, there was a bill to eliminate the Montana renewable portfolio standard that was tabled in committee yesterday.

Okay. And then I missed what you said about the NOL. Did you say last until or through '15?

I said through '15 and I didn't say -- I said at least 2015 -- through 2015. Our expectation is we're going to go past 2015. We're not comfortable at this time, Paul, to tell you if that's 2016 or 2017.

We still evaluating the rules associated. What's getting 50% bonus, what's getting 100% bonus. And until we have clarity around the issue, we're saying at least 2015 at this point in time.

Thank you very much.

Thank you.

Next, we'll go to the line of Brian Russo.

Hi, good afternoon.

Hey, Brian.

Just on the MOUs for wind, can you just be more specific or give us more detail on the regulatory approval process? I mean when you guys will be filing for recovery. I think you previously said second quarter but when might we get a decision. And it looks like, if you do get approval, all of the CapEx will be spent in 2012?

Dave, do you want to provide some comment there?

Sure. Assuming we get the definitive agreements on both projects, we'll be looking at filing, as you say, a preapproval filing in late March, early first part of the second quarter. Then it's a matter of the Commission scheduling hearings and going through a process which may take up to nine months.

We would be looking at trying to get both of those projects put together and in the ground by the end of 2012, if all things go as planned. And that's how we have kind of scheduled them.

So it seems that maybe some of the noise from the legislature about eliminating the RPS maybe have been kind of diminished a little bit by tabling this bill you mentioned earlier?

As far as the specific bill is concerned, yes. And there is a lot of debate in the Montana legislature about the energy policy this year as there often is. For the most part, our approach is better stay the course, give us broad guidelines, stick with them, be consistent, and that certainly is the approach that we're taking with wind resources on our system.

As I mentioned, I think it's important to note as a result of bringing these projects through a bid process, we're able to come in with projects at below -- I'm not sure exactly where, but meaningfully below our voided costs. We think these are projects that have some merit.

Okay. And then the distribution infrastructure filing, you mentioned that will be filed in the second quarter?

That's correct.

Early or late in the quarter?

I'd say probably mid-quarter at this time. We have -- as you heard, we have a number of significant filings coming up, but we're shooting for probably around the middle of the quarter.

The first regulatory filing associated with the DSIP is the request for an accounting order that we filed just a couple of weeks ago.

Okay, got you. And I think in your K -- I think it mentioned $16 million of distribution spend in '11, in addition to the $140 million of base CapEx. Is that accurate?

That's correct.

Okay, what kind of load growth should we expect in 2011 to support kind of the guidance range you've laid out?

I think, Brian, for fairness, we typically targeted about 1% to 2% and that's probably what you should continue to use. That's expecting quite a bit of recovery in that range. I think you could even argue it might be closer to that 1% than 2%. But I think that's the range you should consider.

And how will that compare to operating expense growth or O&M growth?

We're seeing a bit higher O&M expectation in terms of growth. There are actually labor increases at a bit faster clip than that and some other expenses. We have laid that out, if you will, on our EPS bridge.

Okay. So just when looking at your allowed returns '10 -- let's just say for now, given it's a historical test year and it looks like O&M expense might exceed your load growth or sales growth, are we going to see some ROE degradation in Montana until you file for your next rate case?

I would say that after you receive a rate increase and if your costs continue to increase and as we continue to invest more than depreciation, just philosophically we should expect we would have degredation in our ROE.

That's one of the reasons we're looking at the accounting order to help us, so we can make this greater investment as we'd like to in our distribution infrastructure to help assuage some of that impact. We'll look at that but theoretically, you could argue because of 2008 test year, we're already -- will be eating into that ROE a bit.

Lastly, reiterate the income tax rate we should expect in 2011, and is the low rate is a function of the bonus depreciation until you go for your next rate case?

It's a combination. You obviously continue with the repairs but bonuses comes into play as well and we arrange that at 20% to 24%. As I said earlier in the call, we're still trying to take into consideration how, in fact, the new law goes into effect.

All right, thanks a lot.

Moving to our next person, we have a question from the line of Lori Johnstone.

Hi, thank you. I was wondering on the -- I know you don't intend to issue any equity for 2011, I was wondering if you have any need to issue debt?

I think we feel very good about, from a cash flow perspective, we're going to have ample cash flow and, in fact, as I mentioned, on the call, in the scripted part of the call, we expect our cash flow to actually help us deal with our debt-to-cap, bring that in to line.

So unless we have some movement on some growth projects that we aren't talking about today, I don't see any incremental need for debt.

I think any CFO out there right now, if he can term out of his revolver or do something like that with long-term debt, those types of things, we my explore. But at this point in time, we don't have any plans in that regard.

Okay, thanks. And I apologize if you said this and I missed it, but what is the current status of your pension funding?

Yes, at the end of 2010 our funded percentage, we're now at 89% funding. The actions that we took in 2009 to significantly fund that pension plan have really paid dividends for us. So we feel good where we sit today, at 89% and we continue to hope for a strong stock market like the rest of you.

I think we all do on that one. I think that was it for me. Thanks.

Thank you.

Next, we go to the line of James Bellessa.

Hey, guys, this is actually Michael Bates on for Jim.

Hey, Michael.

Hey, I just had one question for you. We saw your dividend increase this morning and one of the first things we wondered about is, number one, is it going to continue growing at this rate?

Number two, with the CapEx that you have on the plate for the next few years we would be surprised you wouldn't try to retain more of your internal cash flow. Can you give a little bit of color that?

Michael, I appreciate the question. As you look at our earnings guidance we provided -- and just for all intents and purposes, assume that this increase of an annual basis is $1.44. Our dividend payout ratio would range in that 60% to 64%. So in the bottom half of our targeted 60% to 70%. And to your point, with the capital plans that we have in place on a going-forward basis, that's the range that we'd like to stay in on a going-forward basis.

Sure. All right, thanks a lot.

The last current questioner in the queue is Jonathan Reeder.

Good afternoon, gentlemen. I was hoping to get a little more clarity on your thoughts around the Montana Public Service Commission. What changes you might see going forward and then how that effects your future rate case filings and the timing.

And as I mentioned, we want to take really a middle-of-the-road approach to our regulators.

The first goal we have is to be as transparent as possible, give regulators as much information as we can, either for anyone in the call who doesn't know there was an election, one of the former Commissioners was termed out. As a result, there are two new Commissioners who have come on board.

Bill Gallagher is the Chairman, he's an attorney from Helena, Montana. Travis Kavulla is from Great Falls, Montana. Both really did hit the ground running. We're doing a lot of homework. We're eager to work with them and provide them as much information as we can.

What would be the timing of your next distribution rate case in Montana? Have you guys figured that out?

We're always evaluating it. Certainly we wouldn't expect to file anything in the current year. We talked about a number of specific dockets that we will be filing this year in terms of something for preapproval for the supply acquisitions and the distribution plan and then the next rate case sometime after that.

Okay, and then if you could just refresh me, you have an appeal of the modified loss revenue adjustment mechanism and the inclining block rates, or whatever. How does that differ from your motion for reconsideration that got denied? Is this appeal still with the Commission or is it in the courts?

It's in the courts. Substantively, the request is exactly the same as what was put in front of the Commission, the outgoing Commission, on a request for reconsideration. And the parties took different positions in the contested case on whether or not there should be a decoupling mechanism and if so, what it should look like, whether or not there should be inverted rates. If so, how they should be set and whether or not there should be a further ROE reduction if there were a form of decoupling adopted.

What's important is that once the Commission issued its order, the three or so parties on this issue -- the Consumer Council, Natural Resources Defense Council and the Human Resource Council, which we're coordinating in their case.

And we managed to agree on an acceptable outcome and that outcome included not going forward with an inverted rate structure. And we are aware that that's -- that's something that was a concern to the new -- to the incoming Commissioners.

We also agreed that although we had differing positions on whether or not there should be decoupling, we all agreed that the version adopted by the Commission really didn't in any way move the ball forward and from an NRDC viewpoint, decoupling was intended as a way to promote even more aggressive approaches to energy efficiency than what the utility is currently taking.

And with the best of intentions, the Commission, rather than creating an incentive or holding the Company neutral, created a real disincentive. We all agreed that was inappropriate.

So in terms of what we recommended as an outcome to the Commission, the inverted rate structure would go away, their particular version of decoupling would go away.

The pre-existing lost revenue adjustment mechanism would remain in place and the stipulation on revenue requirement that, again, was approved on a four to one vote would go back into place.

The stipulation simply read, as to the ROE, that the ROE would be $10.25 and if the Commission adopted decoupling, the Consumer Council reserved its right to argue for a lower ROE.

We reserved our right to argue for a higher ROE. Because we had negotiated what we thought was a very conservative ROE at $10.25, and because we already had a lost revenue adjustment mechanism, we simply had no interest in the kind of the modified decoupling that the Commission came up with on the electric side.

So again, the best of intentions, I think, all around but it was a real step backwards in terms of all of the goals we were trying to achieve.

What we would love to do would be to enter into a stipulation with the Commission that would put the case to bed.

The Commissioners who served on the Commission that approved the stipulations and that adopted their modified decoupling mechanism for the electric side would get a win and that the efficiency programs and the L-RAM would continue in place.

The incoming Commissioners who are concerned about inverted rates would get a win and that the inverted rate proposal would not be adopted and we could focus on very important going-forward concerns.

Does the court have the jurisdiction to strike the second half essentially of that rate order or how does that procedurally work? Does it get opened up where the Commission -- the new Commission then retakes it up, that stipulation agreement?

It would be a little bit premature to say what the court specifically will do, how long the case will go on, whether or not there would be a remand.

An outcome that is available, the parties would support and be presented to the Commission, is a stipulation by the Commission and by the parties to the court, again, that the inverted rate and decoupling would go away and that the full terms of the stipulations that were approved by the Commission -- revenue requirement and allocated cost of service would go into full effect.

I'm not saying that we'll be able to achieve that outcome, but that would be a very, very straightforward, efficient and relatively rapid outcome.

What would be your expected timing on some clarity around this?

The Commission takes actions in noticed meetings and they're busy with lots of things -- they're active in the legislature. I'm confident that they are working on that.

And on our side we've worked very closely with Consumer Council and the other parties to try to identify constructive outcomes and put them in front of the Commission as quickly as we can.

Okay, then a quick housekeeping item with -- with Brian, I guess. For 2011, the effective tax rate of 20% to 24%, I was trying to break it down as to what gets you into that level. And the bonus depreciation, it looks like maybe you have about $2.8 million of expected benefits there and maybe $10.7 million from repairs. If we just keep '11 consistent with '10, and are there any other components?

I think you captured them, Jonathan. The two things.

Remember, we continue to increase in investments of our maintenance CapEx. The repairs in '11 could be bigger than '10 but bonus is the other piece.

Okay. And thank you.

One follow-up question did come in if you have time to address.

That depends on who it's from?

Paul Ridzon.

Are you sure you want to take it?

Just kidding, Paul.

Your load growth is about a dime. What's the embedded kind of percentage load growth that that implies?

Just over 1%.

And that is on a weather neutral basis?

That is a weather neutral basis.

Okay, thank you very much.

And there are no more questions in the queue.

Good. Thank you all very much, look forward to visiting with many of you next quarter if not before.

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