Idacorp Inc (IDA) 2011 Q4 法說會逐字稿

Good day and welcome, everyone, to IDACORP's fourth quarter 2011 conference call. Today's call is being recorded and webcast live. A complete replay will also be available from the end of the day for a period of 12 months on the Company's website at www.idacorpinc.com. (Operator Instructions).

At this time I would like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.

Thank you, Stacy, and good afternoon, everyone. Welcome to our fourth quarter 2011 earnings release conference call. We issued earnings release before the markets opened today, and that document, along with our SEC Form 10-K, is now posted to our IDACORP website at www.idacorpinc.com. We will be using a few slides to supplement today's call, and these are also located on our IDACORP website. We will refer to specific slide numbers as we work our way through today's presentation.

Now moving to slide two. On the call today we have LaMont Keen, IDACORP President and Chief Executive Officer, and Darrel Anderson, Idaho Power President and Chief Financial Officer. We also have other individuals available to help answer your questions during the Q&A period. Before turning the presentation over to LaMont, I will cover a few details with you. First our Safe Harbor statement is on slide three.

Our presentation today contains forward-looking statements, and it is important to note that the Company's future results could differ materially from those discussed. While these forward-looking statements represent our current judgment of what the future holds, these statements are also subject to risks and uncertainties that may cause actual results to differ materially from statements being made today. As a result we caution you against placing undue reliance on these forward-looking statements, which reflect our opinion only as of today. A discussion of factors that could cause future results to differ materially can be found on slide three and in our filings with the Securities and Exchange Commission, which we encourage you to review.

Referring to slide four, I will briefly discuss the financial results from today's earnings press release. Fourth quarter 2011 net income attributable to IDACORP was $9 million, $11.4 million less than last year's fourth quarter. Year-to-date net income attributable to IDACORP was $166.7 million, $23.9 million more than 2010.

Idaho Power's fourth quarter 2011 net income was $9.3 million, which was $9.6 million less than the fourth quarter of 2010, while Idaho Power's annual 2011 net income was $164.8 million, which was $24.1 million more than 2010.

IDACORP earnings decreased by $0.23 per diluted share quarter over quarter to $0.18 per diluted share, but increased by $0.41 per diluted share on an annual basis to $3.36 per diluted share. As indicated in today's earnings press release, our current full year 2012 earnings guidance is in the range from $3.00 to $3.15 per diluted share.

Darrel will speak more about the guidance range later on the call. I will now turn the presentation over to LaMont.

Thanks, Larry, and welcome to our participants on this first call of the new year. We thank you for your interest in IDACORP. Larry just summarized our 2011 financial results, so I will spend a few minutes discussing other accomplishments in 2011 and some of our initiatives going forward.

As we reflect on our accomplishments in 2011, we do also look forward to 2012 and beyond. And to that end late in 2011 we announced leadership changes, which took effect on January 1. Beginning January 1, Darrel Anderson assumed the role of President and Chief Financial Officer of Idaho Power and will continue as Executive Vice President and Chief Financial Officer for IDACORP. In addition to Darrel's advancement, Dan Minor was named Executive Vice President and Chief Operating Officer of Idaho Power. Steve Keen was also promoted to Senior Vice President of Finance and Treasurer of Idaho Power, and both Dan and Steve are joining us on the call today. The transition has been thoughtful and collaborative and continues our legacy of strong leadership and leader development at IDACORP and Idaho Power.

Moving on to regulatory matters. The fourth quarter of 2011 was a busy one for our Regulatory Affairs Department and for our Company as a whole. On December 30 the Idaho Public Utilities Commission issued an order on Idaho Power 2011 general rate case, increasing base rates effective January 1, 2012, for a settlement agreement reached September 23 with the Idaho commission's staff, customer groups and the Company. This resulted in a $34 million increase in Idaho jurisdiction base rate revenue and a 7.86% authorized rate of return on an Idaho jurisdiction rate base of $2.36 billion.

In the fourth quarter we also received a favorable commission decision regarding our continued ability to use accelerated deferred investment tax credits, or ADITCs. Now, though Darrel will discuss this order later on in the call, I wanted to acknowledge the benefit of this mechanism in providing earning support over the next three years.

Changing tracks a little bit, we also continue to work to secure a reliable energy future. Our 300 megawatt Langley Gulch natural gas-fired power plant continues to move toward completion. The project also remains on schedule and within budget, with major milestones occurring in the next several months. These include first fire by early April and expected commercial operation by July 1, 2012. The Company plans to file for project cost recovery with the IPUC, requesting that new rates, if approved, go into effect at commercial operation in July.

Large scale transmission projects continue to be a focus as well. Efforts in 2011 with the Bonneville Power Administration, or BPA, and PacifiCorp led to a joint funding agreement. Together with BPA and PacifiCorp, Idaho Power is participating in a joint funding arrangement for funding federal, state, and local permitting for the 300 mile Boardman to Hemingway project, or B2H. To date we have submitted applications to the Bureau of Land management to obtain that authorization for B2H to cross federal lands.

While the B2H project will be essential to move electricity to and from the Pacific Northwest, the Gateway West project will allow Idaho Power to site future generating resources in Southern Idaho and deliver energy to customers. Idaho Power and PacifiCorp are currently parties to a cost sharing arrangement for portions of the proposed 1,150 mile Gateway West project. Participating in both these projects helps to ensure we have capacity and options available to build for future economic development as the economy rebounds.

Additionally, the fourth quarter brought the completion of our three year advanced metering infrastructure project. We have installed nearly 500,000 smart electric meters for customers throughout our service area. These new meters are the foundation of our ongoing smart grid project. The smart meter installation allows the Company to collect 13 million meter reads per day. It is also estimated 80 vehicles -- or eliminated 80 vehicles from the Idaho Power fleet, saving on the fuel and maintenance costs associated with driving 1.6 million miles per year to read meters.

The availability of competitively priced electric service is essential to a healthy economy and necessary to attract, retain and expand business and industry. This proved true once again, in November as New York base Agropharma chose Twin Falls, Idaho, as home to its newest multimillion dollars processing plant for its Greek yogurt brand Chobani. The plant is anticipated to bring 400 new jobs to the service area and is scheduled to start production later this year.

Changing tracts again a little bit to the water year. What began as a challenging 2012 water year, mitigated by good reservoir storage carryover, [has improved] in recent weeks thanks to a better late than never start to winter. January and February storms in the service area brought much needed precipitation and snow pack accumulations in the mountains. However, we are still below normal in the Snake River basin.

Due largely to favorable water conditions, hydroelectric generation comprised 69% of Idaho Power's total system generation during 2011, compared to 51% during 2010. As of February 22, Idaho Power expects hydro generation during 2012 to be in the range of 7.5 million to 9.5 million megawatthours, compared to 10.9 million megawatt hours in 2011 and 7.3 million megawatt hours in 2010. The range of expected generation is the result of above normal reservoir storage carryover that I mentioned earlier, combined with slightly below normal precipitation year-to-date and normal precipitation expected over the balance of the year. Median annual hydro generation is 8.6 million megawatt hours.

For nearly a century Idaho Power has been committed to clean energy. Today approximately half of the energy in our portfolio is generated from hydro, wind, solar, biomass and geothermal resources. We are proud of our relatively small carbon footprint and history of responsible energy generation. However, over the past few years renewable energy projects, especially wind projects, which traditionally have qualified for high rates under the Public Utility Regulatory Policies Act, or PURPA, have put an undue burden on the Company and our customers.

To address some of the concerns related to the rapid influx of PURPA projects, in 2010 we worked with Rocky Mountain Power and Avista to file an application with the Idaho Public Utilities Commission to lower the threshold for qualifying PURPA projects from 10 average megawatts to 100 kilowatts. That initiative was successful, as the IPUC reduced the eligibility cap to 100 kilowatts for wind and solar projects that qualify for higher PURPA rates. This year we are focused specifically on the price calculation, and on January 31, 2012 filed testimony with the IPUC to develop a more accurate and fair method for calculating the prices we pay to developers of PURPA qualifying projects. We feel that renewable energy resources have a place in our generation portfolio. However, the cost should not place an undue burden on our customers. The matter is scheduled for hearings at the IPUC in August of this year.

Moving on to EPA rules. Slide five shows the estimated impact on our coal fleet of the EPA's current air quality regulations as we understand them today. In general, environmental laws and regulations increased the cost of operating power generation plants and constructing new facilities. They can require that Idaho Power install additional pollution control devices at existing generating plants, or even require that Idaho Power shut down certain power generation plants. We continue to monitor developing legislation and increased regulation concerning greenhouse gas emissions and the potential impacts on power generation facilities. As legislation/regulation further develops, we will continue to assess the impact on the cost to operate effective facilities. As to the new [MACK] or [MATCH] -- rules whichever acronym you prefer -- specifically, based on our evaluation to date, we do not foresee any plant closures and expect that related compliance costs will not be substantial.

Finally, an update on a topic we discussed in our last call, and I will refer you now to slide six. On January 19, 2012, the IDACORP Board of Directors increased the 2012 regular cash dividend -- quarterly dividend on IDACORP common stock to $0.33 per share from $0.30 per share, representing a 10% increase. The quarterly dividend is payable February 29 to IDACORP shareholders of record on February 6, 2012.

I will now turn it over to Darrel, who will further update you on our financial results.

Thanks, LaMont, and good afternoon, everyone. LaMont highlighted some of our key operational accomplishments in 2011. I want to spend a little time reviewing some of the financial highlights, and then take a look at the outlook for 2012.

We recorded fully diluted annual earnings per share of $3.36, which marks the fourth consecutive annual increase in earnings. On slide seven, we present a reconciliation of net income attributable to IDACORP from 2010 to 2011, which reflects an increased net income of $23.9 million. The full reconciliation table is included in the Form 10-K we filed this morning.

Operating income was enhanced by $43.5 million due to base rate changes, improved sales volumes, increased transmission revenues and changes in power supply costs net of the related PCA mechanisms. These revenue related increases were offset by increases in other operating and maintenance expenses of $24.4 million, depreciation of $3.9 million, and property tax expense of $4.8 million. The change in operating and maintenance expense is due to an $11.5 million increase in pension expense associated with the pension recovery rate orders, which are earnings neutral.

Increase in payroll-related expenses of $5.7 million, and $5 million increase in maintenance expenses at our thermal plants. These increases were offset by lower legal expenses of $2.3 million. Prior to recognizing the impacts of the sharing mechanism, operating income was $11.5 million. We anticipate that factors that contributed to the increase in operating income in 2011 will act as a catalyst in reducing our potential reliance on accumulated deferred investment tax credits in 2012.

2011 included recognition of $56.9 million of income tax benefits from a tax accounting method change relating to approval of Idaho Power's method of uniform capitalization. This method contributed to the triggering of the sharing mechanism under Idaho Power's January 2010, Idaho settlement agreement, which provides that Idaho Power earnings over a 10.5% return on year-end equity in the Idaho jurisdiction are to be shared equally between Idaho customers and the Company. The sharing mechanism, along with the December 12, 2011, IPUC settlement I will discuss momentarily, resulted in Idaho Power recording an accrual for $27.1 million refund to Idaho customers, with the impact of reducing operating revenues for the period.

An additional $20.3 million has been recorded as pension expense in accordance with the December 2011 settlement stipulation for a total benefit to customers of over $47 million. Also contributing to the year-over-year earnings improvement at Idaho Power was an $11.6 million increase in allowance for funds used during construction, directly reflecting the Company's increased construction expenditures over 2010 levels.

And finally, the $52.1 million reduction in income taxes was primarily driven by Internal Revenue Service settlements for the UNICAP and repairs method changes of approximately $27.8 million, and lower tax expense due to both pretax -- due to both lower pretax earnings and net increases in tax deductions at Idaho Power.

Next I will discuss the mechanics of the additional accumulated deferred investment tax credit extension in the Idaho jurisdiction LaMont alluded to earlier. For this discussion, please refer to slide eight.

The settlement stipulation, which is separate from our general rate case settlement, provides for the following. If Idaho Power's Idaho jurisdictional return on year-end equity for 2012, 2013 or 2014 is less than 9.5%, then Idaho Power may use up to $45 million of additional accumulated deferred investment tax credits to help achieve a minimum 9.5% return on equity in the applicable year. Idaho Power is limited, however, to using no more than $25 million of the additional accumulated deferred investment tax credits in 2012.

If Idaho Power's year end return equity in the Idaho jurisdiction is between 9.5% and 10%, there would not be any use of tax credits or any sharing. For earnings between 10% to 10.5%,the sharing is equal; 50% to the customer, 50% to the Company. For earnings over 10.5%, the sharing is 75% to the customer and 25% to the Company.

In consideration for the ADITC extension, the settlement stipulation provided that Idaho Power would increase its allocation to Idaho customers from 50% to 75% of Idaho Power's share of 2011 Idaho jurisdictional earnings over a 10.5% return on year end equity. The total 2011 benefit to the Idaho customers was just over $47 million.

Now I will move to IDACORP's 2011 liquidity position and the 2012 expected debt and equity financing requirements. IDACORP's cash flow from operations for 2011 was $310 million, an increase of $5 million from 2010. On October 26, 2011, we executed a new five year credit agreement, which increased the size of the IDACORP facility from $100 million to $125 million, but maintained the Idaho Power facility at $300 million. Commercial paper outstanding at IDACORP as of December 31, 2011, was $54.2 million, compared to $66.9 million at December 31, 2010. Idaho Power Company had no commercial paper outstanding at either date.

Also as of December 31, 2011, there were 3 million IDACORP common shares available for issue issuance under the continuous equity program. We expect minimal needs for internal financing in 2012 at both IDACORP and Idaho Power, other than issuances of IDACORP common stock under the dividend reinvestment and employee related plans. We do, however, monitor debt and equity market conditions and may issue debt or equity securities when we determine that under the circumstances and in light of the timing and extent of financing needs, conditions are favorable for issuance of such securities.

IDACORP and Idaho Power seek to maintain a capital structure of approximately 50% debt and 50% equity, and maintaining a capital structure at or near this ratio has an impact on whether IDACORP or Idaho Power from time to time issues debt or equity securities and the mix of those securities. As of December 31, 2011, IDACORP's capital structure consisted of 52% equity and 48% debt, which decreases the likelihood that IDACORP will issue equity securities during 2012. For the remainder of 2012 we will continue to focus on controlling costs and generating sufficient cash from operations to meet operating needs and contribute to capital expenditures requirements.

I will now update you on a couple of the 2012 key operating and financial metrics. These are on slide nine. Idaho Power's capital requirements over the next three years are forecasted to be lower than recorded in the recent past. We are expecting to spend between $230 million and $240 million in 2012, of which $30 million to $35 million is estimated for the completion of the Langley Gulch power plant. From inception to 2009 to December 31, 2011, we have spent $355 million on this project. Idaho Power's estimate of ongoing capital expenditures in total for the years 2013 to 2014 is expected to be in the range of $490 million to $500 million, with a large portion associated with environmental regulation costs.

The estimated hydroelectric generation range of 7.5 million to 9.5 million megawatt hours based on current reservoir storage levels as well as current forecasted weather conditions. Based on these assumptions and taking into account our settlement stipulation with the Idaho commission, we are initiating 2012 full-year earnings per share guidance in the range of $3.00 to $3.15 per diluted share. The earnings range assumes that the Langley Gulch plant is commercially available as of July 1, 2012, and we are earning a return on the plant commencing as of that date. This also includes an estimated use of additional accumulated deferred investment tax credits of less than $5 million in 2012.

This concludes my financial update. Now we would like to respond to your questions.

Thank you. (Operator Instructions). Your first question comes from the line of Paul Ridzon with KeyBanc. Please proceed.

Good afternoon.

Hi, Paul.

How much AFUDC did Langley Gulch earn in 2011?

Paul, we obviously we disclose the total amount of AFUDC, but don't have disclosed the specific amount associated with Langley Gulch. You could do a rough ballpark I think if you took the beginning and ending balances -- or took a look at the end of the year balance that we mention, the $355 million, although there is some AFUDC in that number. And we -- I don't have a number to give you for specific to Langley Gulch, but you could ballpark that number probably based on that capital balance.

What was the capital balance the prior year?

I don't have that here in front of me, Paul.

Do you have what total AFUDC was for 2011?

Hang on one second, I can tell you. It is -- one second. Looks like about $38 million total.

And you said -- you kind of broke off, but did you say that guidance assumes ADITCs of less than $5 million?

Less than $5 million, that's right.

Okay. Thank you very much.

Your next question comes from the line of Brian Russo with Ladenburg. Please proceed.

Good afternoon.

Hi, Brian.

Just to comment on the dividend policy. I think your target payout is 50% to 60%, and based on the recent dividend boost and the midpoint of your guidance, you are at 42% payout in 2012. Below your target. Will the dividend be reviewed only once-a-year, or is it possible that the Board could review the dividend again later in 2012 for a possible second increase?

Brian, this is Darrel. I will have LaMont address that, but one of the things -- I mean, obviously the Board addresses the dividend every quarter, first of all, and so that is kind of the basis. I will let LaMont kind of address the more overarching question as to the timing and extent of possible future changes.

Hi, Brian, this is LaMont. Since the Board has adopted the policy, and we are certainly glad they did and have taken the first step toward implementing it, it's certainly reasonable to expect that over time we will periodically review that and take additional steps to hit our target. We have not set what that time table will be. It is probably not unreasonable to expect that it be reviewed annually, but the Board could review that at any point. But we have set the target and intend to move that direction through time.

Okay. And I guess based on your hydro generation output expectations for the year and the medium, I guess could be characterize hydro conditions in your region as near normal?

Brian, I think, based on the range that we have provided as it relates to the hydro, we are benefited by, first of all, last year's reservoir carryover as we go into this year. So that -- we are above normal there, so that is helping what LaMont mentioned in his opening remarks about we are below normal on precipitation to date. So kind of the combination of above average carryover combined with below normal precip to date gives you a range that comes in and around the median generation number. It's kind of if you look at the midpoint of our range. And so that is based on information we know today, and as that changes we will update you at the end of the first quarter with -- as the snow pack settles in and we have a better number for you.

Okay. Great. And --

It's really a combination of both.

Okay. And then on the Boardman to Hemingway line, I think previously you guys were assuming an ownership level of north of the 21% that's been kind of outlined in the funding agreement, and I'm just curious, is that going to be your ownership percentage at 21%? And then when might we see the CapEx spend kind of tick up on that?

Brian, I'm going to ask Dan Minor, who is our EVP and COO, to talk a little bit about the timing. He was instrumental in helping getting that effort put to bed, so I will let him comment on that.

This is Dan. So the project itself, what we have done today is we assumed a permitting percentage for the sake of bringing the other partners into the project. And the number was always kind of in that range for us, somewhere between 20% and 30%. The 21% that we landed on actually matches very closely to what our operational needs are from the project going forward.

The good news is the other partners that we brought in have very complementary needs to the Company and have need both in Oregon and in Idaho to get across the system. So at the end of the project, when we believe we have permits, we will also potentially have partners that we can construct the projects with.

In terms of the CapEx spend, that's -- we would still want to see it begin somewhere in that 2016 time frame, but it largely depends on permitting. And that is both in the BLM's hands as well as in the Oregon Department of Energy's hands through their [aspect] process. We will do everything we can to move it forward, but it is really their process.

I'm sorry --

Brian, this is Darrel. Just to follow up, with our current targeted in-service date of 2016, that suggests -- it's probably about a two year build cycle there, so if you back that up, that would probably be sometime in 2014 is where you would start spending the money on that project. But again that is dependent upon us getting some additional input on the permitting and siting process before we start spending any -- making any major commitments on the capital required to begin construction. So the earliest that would be would be sometime in 2014, depending on the timing of the permitting process.

Right. And I guess --

But you see in our number that we gave you does not include any hard dollars for construction. It just includes permitting and siting expenditures. On the [range] that we gave.

Got you. And to clarify, it is targeted in your IRP for a mid-2016 start?

We hope to be finished with the project by then. I think I'm the one that confused you, but we hope to be done with it by then. But as Darrel said, it is probably a two year construction window and -- so if you back up, we would probably look to start it in 2014, depending on permitting.

Okay, great. And then I think it is noteworthy that you only expect to use less than $5 million in ADITCs in 2012, and you mentioned briefly some mechanisms that help support the operating income. I was wondering maybe if you could elaborate on that a little bit?

I think, Brian, what we are referring to there really is, it is a culmination of a lot of the activity in 2010 and 2011 in the form of base rate changes that we have been able to get into effect combining with the rate changes that went into effect on January 1 of 2012. When you [take a] look at all of those, we saw an increase in the operating income before the other mechanisms kicked in, and we believe that -- those will help carry us forward to minimize the amount of additional ITCs that we would otherwise have to use to support the 9.5% in Idaho.

So we believe that those will carry forward. As we continue to also manage the business and try to manage expenses, that does reduce the amount of ITCs that we might otherwise have to use. And so we think that was notable -- the reason you saw it in the reconciliation, we thought that the increase in operating income is notable and that the business -- from a regulatory perspective we are getting things set up in order to move forward and be able to live under this three year agreement we have with the Idaho Commission.

Then lastly just the Hoku contract settlement that I guess Hoku put a press release out on. Can you discuss that a little bit?

Brian, well, Greg Said, who is -- heads up our Regulatory Affairs, and his group is the one that kind of worked through the reformation of that contract, so I will have Greg talk a little about the Hoku contract and what it means to us.

Yes, this is Greg. With regard to the Hoku contract, essentially the agreement that was reached by the Company, Hoku and the commission staff was an approach that did not relieve Hoku from their contractual obligations under the current contract, but restructured the timing of payments so that there was relief in the near term months to Hoku and more obligation on the back end of the contract. And the reformation included some upfront payments from Hoku that would go directly to Idaho Power in the near term. With their anticipated reduction in use of electricity in the near term, it was determined that their deposit requirements would be reduced from $4 million to $2 million, and we had already had the $4 million on deposit. So we are able to apply $2 million of that deposit to the upfront obligation to the Company, and then have ongoing $100,000 per month payments from Hoku to cover what the upfront requirements of the Company would be.

The back end nature of the reformation is basically customer dollars. Because the Hoku first block energy payments are treated as a -- in a manner similar to surplus sales in our power cost adjustment, that reflects a benefit to our customers over time. And while Hoku is not making those payments today and are deferring those to a later point in time, that is where the customer benefit is returned at a future time under the reformed contract.

So I guess the -- to again summarize that, the full obligation of Hoku under the original contract remains the same. There is just a shifting in the timing of when those payments are made, with the Company retaining the benefits early in the reformed contract, and the customer benefits being returned later in the reformed contract.

Okay, great. Thank you very much, and congratulations on a good year.

Thanks, Brian. Appreciate it.

Your next question comes from the line of James Bellessa with D.A. Davidson. Please proceed.

Good afternoon.

Hi, Jim.

The earnings guidance that you've provided, $3.00 to $3.15, is the upper end assume no ADITC and the lower end something less than $5 million?

Now, Jim, we probably aren't going speak to the upper or lower end of that range. What we basically kind of included in there is an estimate that the range includes less than $5 million of ITCs in total to be utilized. And so I don't think we want to try to get into guessing at the higher or lower end of the range. But within that range we are going to use something less than $5 million.

You are assuming a normal hydro year approximately. Why do you need any relief from ADITC at all?

Well, Jim, I think part of the challenge is if expenses weren't flat, then -- and if we could do that where we do have some upward pressures on some expenses, I think we could possibly try to not have to use any ITCs. But again, if we are talking about less than $5 million that is not a lot of ITCs to get us to -- even within Idaho to the 9.5% level.

So I think that mostly -- I mean if I was having a higher number than that, I think it would raise another question on the issues around lag and some of those things, but in the fact that we are using less -- projected to be less than $5 million says we are doing a pretty good job. We are not managing expenses down -- increases to zero, but we are doing the best we can in trying to manage the business. And at the same time we also aren't seeing necessarily the growth on the revenue side that we otherwise would like to see again in an economy that still isn't hitting on all cylinders. So it is kind of a combination of both of those things, requiring us to estimate, at least today, that we might use a little bit of ITC.

This guidance range that you provided assumes what tax rate?

We haven't provided you an estimated tax rate, but what I would probably be able to tell you is, if you look in our 10-K, and if you took a look at the last couple of years, and you adjust -- there is some -- you can see the impact of some of the tax adjustments running through the effective rate schedule. And when you look at that, there is a range of tax rates that are there after you adjust for those, and I think they ended up, if you adjust for those, you are going to be some where in the 15% to 20% range if you do that math in some of those ranges.

We should be back to a arguably more normal tax situation for us. But you have to look at historical; we have been on the low side anyway because of the flow-through adjustments that we have, so you have to kind of look at that. But once you adjust for some of those one off items, you get to something that might be a little more I'm going to say normal, but because we are flow through it is not necessarily normal.

And normal would be 15% to 20%?

If you recall back to when we used to give effective tax rate ranges we were kind of in and around those ranges, maybe a touch higher. But again we still have -- we do have the impact of some flow-through adjustments that do have the impact of reducing that effective rate down to in and around that range. We haven't given tax guidance for a year or are so now, and we are really not looking to do that now. So my best advice to you is to kind of go back to the table, take a look at that, adjusting up for some of the items that we discussed this year and last year. Which are pretty well laid out in that table.

The Hoku arrangement calls for a one-time payment of $3.8 million. The first $2 million paid by deducting it from the $4 million deposit previously paid. So is that a first quarter earnings benefit? Is that (inaudible -- multiple speakers) --

No, Jim, that number will end up being amortized really over the life of the reformed -- over that 18 month period. So we will recognize that over that period of time.

Thank you very much.

Thanks, Jim.

Your next question comes from the line of Sarah Akers with Wells Fargo. Please proceed.

Hey, good afternoon.

Hi, Sarah.

Just a follow-up on Brian's question on the B2H project and, I guess, both transmission lines. You mentioned that one of the drivers for the project is to access generation capacity as the economy rebounds. I'm curious, if those projects end up getting delayed, when do you see kind of a firm need to either build additional generation or pursue other investments to satisfy system needs just based on your current demand forecast and growth outlook in the region?

Well, with Boardman/Hemingway, which is a nearer project -- nearer term project for us, that line is really being built to access resources in the northwest, which is already there, available today, that we can't bring home because in certain times of the year those pipes are full. And so those resources really are there already. And so it is a matter of us getting through this permitting and siting and getting the line built so we can access that, which is what we included in our IRP -- in our most recent IRP, which is why that particular project is -- goes to the top of the heap for us, is because the resources are really already there.

Okay. So if that gets delayed, would you look to build another unit at Langley, or is -- you're just very focused on being able to access that in one way or another?

We would continue to evaluate those needs. Again, we will have another IRP that we will be kicking out and evaluating, and it will assess the status of where we are at with B2H as well as other things that moved in the meantime, to continue to evaluate what is going to be that best resource. But today, in our last IRP, Boardman to Hemingway goes to the top of the list.

Okay. And then in terms of Gateway West, are initial phases of that project still slated to come online in the 2015 to 2017 time frame.

We are going to have Vern Porter, who manages all those projects, kind of address the Gateway West project for us.

Hi. I think you are pretty close in your range. We've got the draft environmental impact statement out in July of 2011, and we expect a final to be out in about a year from then, maybe toward the end of this year. So you could probably expect a record of decision in mid-2013, which would put you in that general range of 2017 time frame. It'd be built in segments as the companies need to do so.

Okay. Thanks a lot.

Thanks, Sarah.

(Operator Instructions). That does conclude the question and answer session for today. Mr. Keen, I will turn the call back to you.

All right. Thank you, Stacy, and thank you all for participating on the call this afternoon, and have a good day. Bye.

That concludes today's conference. Thank you for your participation.