IDACORP, Inc.

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 2. 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'll cover a few details with you. First, our safe harbor statement is on Slide 3.

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 3 and in our filings with the Securities and Exchange Commission, which we encourage you to review.

Referring to Slide 4, I'll 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 to $3.15 per diluted share.

Darrel will speak more about the guidance range later on the call. I'll 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 Miner 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's 2011 general rate case increasing base rates effective January 1, 2012, for a settlement agreement reached September 23 with the Idaho Commission 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 want to acknowledge the benefit of this mechanism in providing earnings support over the next 3 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 transmission line project or B2H.

Today, we have submitted applications to the Bureau of Land Management to obtain authorizations 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 3-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's also estimated 80 vehicles -- or eliminated 80 vehicles from the Idaho Power fleet saving on the fuel and maintenance cost 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-based Agro Farma chose Twin Falls, Idaho as home to its newest multimillion-dollar processing plant for its Greek yogurt brand, Chobani.

The plant is anticipated to bring 400 new jobs to our service area and is scheduled to start production later this year.

Changing tracks 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 our 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 megawatt-hours compared to 10.9 million megawatt-hours in 2011, and 7.3 million megawatt-hours in 2010.

The range of expected generation is a 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 a 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 5 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 increase 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 increase 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 effected facilities.

As to the new MACT 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'll refer you now to Slide 6. 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 shareholder 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 7, we present a reconciliation of net income attributable to IDACORP from 2010 to 2011, which reflect an increase in 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 the 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'll 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 8.

If Idaho Power's Idaho jurisdictional return on year-end equity for 2012, '13 or '14 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 on 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 Idaho customers was just over $47 million.

Now I'll 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 5-year credit agreement which increased the size of the IDACORP facility from $100 million to $125 million, but maintaining 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 issuance under the continuous equity program. We expect minimal need for external 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 a 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 expenditure requirements.

I'll now update you on a couple of the 2012 key operating and financial metrics. These are on Slide 9.

Idaho Power's capital requirements over the next 3 years are forecasted to be lower than recorded in the recent past. We're 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 is 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 to $3.15 per diluted share. The earnings range assumes that the Langley Gulch power plant is commercially available as of July 1, 2012, and we are earning a return on the plant commencing on 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 updates. Now we would like to respond to your questions.

How much AFUDC did Langley Gulch earn in 2011?

Paul, we obviously -- we disclosed the total amount of AFUDC, but we 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 year balance that we mentioned, the $355 million, although there is some AFUDC in that number.

And I don't have a number to give you specific to Langley Gulch, but you could ballpark that number probably based on that capital balance.

What was the capital balance of the prior year?

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

Do you have the total AFUDC was for '11?

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.

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're at 42% payout in '12, 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 '12 for a possible second increase?

Brian, this is Darrel. I'll let LaMont address that, but one of the things, I mean obviously, the board addresses the dividend every quarter, first of all.

So that's kind of the basis. I'll let LaMont kind of address the more overarching question as to the timing and extent of possible future changes.

Brian, this is LaMont. Since the board has adopted the policy, and we're certainly glad that 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 timetable will be. It's 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 can we characterize hydro conditions in your region as near normal?

Brian, I think, based on the range that we provided as it relates to the hydro, we're benefited by, first of all, last year's reservoir carryover as we go into this year. So that -- we're above normal there.

So that's helping what LaMont mentioned in his opening remarks about we're below normal on precipitation to date. And so kind of the combination of above average carryover combined with below normal precip [precipitation] to date gives you a range that comes in and around the median generation number, kind of if you look at the midpoint of our range.

And so that's based on information we know today. And as that changes, we'll update you at the end of the first quarter with -- as the snowpack settles in, we have a better number for you.

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 pick 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'll let him comment on that.

This is Dan. So the project itself, what we've 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've landed on actually matches very closely to what our operational needs are from the project going forward.

So the good news is the other partners that we brought in had 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'll also potentially have partners that we can construct the projects with.

In terms of the CapEx spend, we would still want to see it begin somewhere in that 2016 timeframe, but it largely depends on permitting. And that's both in the BLM's hands as well as in the Oregon Department of Energy's hands for their aspect [ process.

] So we'll do everything we can to move it forward, but it's really their process.

Brian, this is Darrel. Just a follow-up.

With our current targeted in service date of '16, that suggests it's probably about a 2-year build cycle there. So if you back that up, that would probably sometime in '14 is where you would start spending some money on that project.

But again, that's dependent on us getting some additional input on the permit 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 some time in '14, depending on the timing of the permitting process.

But you see in our number that we gave you does not include any hard dollars for construction, just includes permitting and siting expenditures that we gave you.

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

We hope they'd be finished with the project by then. I think I'm the one who confused it, but we'd be -- hope to be done with it by then.

But as Darrel said, it's probably a 2-year construction window, and so if you back up, we'd probably look to start it in 2014 depending on permitting.

Okay, great. And then, I think it's noteworthy that you'll only expect to use less than $5 million in ADITCs in '12 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're referring to there really is, it's a culmination of a lot of the activity in 2010 and 2011 in the form of the 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 came up [ with ] 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're getting things set up in order to move forward and be able to live under this 3-year agreement we have with the Idaho Commission.

All right. And then lastly, just the Hoku contract settlement that I guess Hoku put a press release out, can you discuss that a little bit?

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

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 the 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's 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's 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.

The earnings guidance that you've provided, $3 to $3.15, is the upper end assume no ADITC and the lower end something less than $5 million?

No, Jim, we probably aren't going to 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're going to use something less than $5 million.

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

A 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're talking about less than $5 million, that's 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. And the fact that we're using -- projected to be less than $5 million shows that we're doing pretty good job.

We're not managing expenses down, increases to 0, but we're doing the best that 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's kind of combination of both of those things which is 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 -- you can see the impact of some of the tax adjustments running through the effective rate schedule. And when you look at that, there's a range of tax rates that are there after you adjust for those.

And I think they ended up, if you adjust for those, they're going to be somewhere in the, I don't know, 15% to 20% range, if you do that math, in some of those ranges. We should be back to arguably a more normal tax situation for us, but you have to look at historically, we've 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 oneoff items, you get to something that might be a little more, I'm going to say, normal. But because we're flow through, it' not necessarily normal.

And normal would be 15% to 20%.

You know, if you recall back to when we used to give effective tax rate ranges, we were kind of in and around those ranges, maybe in 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 so now, and we're really not looking to do that now. So my best advice to you is to kind of go back to that table, take a look at that, adjusting out 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 onetime payment of $3.8 million. The first $2 million will be paid by deducting it from the $4 million deposit previously paid.

So is that a first quarter earnings benefit? Is that -- all of it...

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

Just a follow-up on Brian's question on the B2H project and I guess both transmission lines. You mentioned that, that one of the drivers for the projects is just 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 the growth outlook in the region?

Well, with Boardman to Hemingway, which is the 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 our full. And so those resources really are there already.

And so it's a matter of us getting through this permitting and siting, getting the lines built so we can access that, which is what we've 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'll have another IRP that we'll be kicking out and evaluating, and it will assess the status of where we're at with B2H as well as other things that have 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 is still slated to come online in the 2015 to 2017 timeframe?

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

I think you're pretty close in your range. We've got the draft environmental impact statement out in July of '11 and we expect the final would 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 should put you in that general range of 2017 timeframe to be built in segments as the companies need to do so.

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

Bye.