Idacorp Inc (IDA) 2011 Q2 法說會逐字稿

Good day and welcome everyone to the IDACORP's second quarter 2011 conference call. Today's call is being recorded and webcast live. A complete replay will 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'd like to turn the call over to the Director of Investor Relations, Mr. Lawrence Spencer. Please go ahead, sir.

Thank you, [Deanna], and good afternoon, everyone. Welcome to our August 4, 2011 earnings release conference call. We issued our earnings release before the markets opened today and that document along with our SEC Form 10-Q 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 and Idaho Power President and CEO, and Darrel Anderson, IDACORP and Idaho Power Executive Vice President of Administrative Services and CFO. 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 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 risk 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.

Turning now to slide four, I'll briefly discuss the financial results from today's earnings press release. Second quarter 2011 net income attributable to IDACORP was $20.9 million, $18.3 million less than last year's second quarter. The 2010 second quarter included a $25 million income tax benefit from a tax accounting method change of Idaho Power Company for repair-related expenditures.

Year-to-date net income attributable to IDACORP was $50.6 million, $4.6 million less than the first six months of 2010. Idaho Power's second quarter 2011 net income was $20.7 million compared to $38.8 million in the second quarter of 2010, while Idaho Power's year-to-date 2011 net income was $50.5 million, which was $6.5 million less than the same period in 2010.

IDACORP earnings decreased by $0.40 per diluted share quarter-over-quarter to $0.42 per diluted share and by $0.13 per diluted share on a year-to-date basis to $1.02 per diluted share. As indicated in today's earnings press release, our current full-year 2011 earnings guidance remains in the range from $2.80 to $2.95 per diluted share. Note that our 2011 guidance continues to exclude potential benefits that would result from the settlement of Idaho Power's uniform capitalization tax method change.

I'll now turn the presentation over to LaMont.

Thanks, Larry and welcome to our call participants. We thank you for your interest in IDACORP. IDACORP's second quarter 2011 results are in line with our expectations. As the second quarter is generally a transition between our heavier winter and summer load periods and is typically lighter for retail energy sales and earnings.

Our quarterly results were helped by increased retail base rates and amortization of investment tax credits when compared to 2010. These benefits were offset, however, by reduced energy sales to our irrigation customers due to wetter and cooler weather, increased maintenance expenses at our coal-fired facilities and decreased earnings from coal sales.

Hydroelectric generating conditions improved in 2011 versus 2010 and were the catalyst for retail rate decreases under our power cost adjustment mechanisms in both Idaho and Oregon. Darrel Anderson will discuss the quarterly financial results in additional detail after I conclude my comments.

I would now like to turn our attention to a discussion on other current topics, including current regulatory activities, operations planning and customer satisfaction, all of which position Idaho Power for the future. On the regulatory front, Idaho Power filed general rate cases with both the Idaho and Oregon Public Utilities Commissions to seek timely recovery of investments and expenses needed to continue to provide safe, reliable energy services to our customers. The cases were filed on June 1 and July 29 respectively. Idaho's general rate case seeks to increase rates by $82.6 million or 9.9%. Oregon's general rate case filings seeks an increase of $5.8 million or 14.7%.

Slide 5 shows key metrics for both of these filings. If approved, the requested effective date in Idaho is January 1, 2012 and in Oregon is June 1, 2012.

In June, the Idaho Public Utilities Commission changed the capacity eligibility requirements for federal Public Utility Regulatory Policies Act qualifying facilities. The order lowered the threshold for wind and solar qualifying facilities from 10 average megawatts to 100 kilowatts.

As discussed in Idaho Power's various filings with the IPUC during those proceedings, Idaho Power believes this change to the eligibility standards was the sensible thing to do and helps ensure dependable, responsible and fair priced energy when our customers need it. We will still negotiate with independent power producers with wind and solar facilities that provide more than 100 kilowatts, which allows us to explore potential new generation resources in the context of our IRP, ensuring both planning and spending are more diligent and prudent.

In June we also filed our 2011 IRP, or Integrated Resource Plan, with the Idaho and Oregon commissions. The IRP is our 20-year roadmap to plan for our customers' energy requirements. The IRP reaffirms our commitment to initiatives such as our Langley Gulch natural gas fired facility and the Boardman to Hemingway 500 kilovolt transmission project as well as continuing investments in cost-effective energy efficiency programs.

Hydroelectricity will continue to be our primary base generation resource. And by 2030, we are forecasting a reduced reliance on coal and see a greater emphasis on natural gas, wind, geothermal and solar. Solar resources, in particular typically deliver energy during the time of day when Idaho Power's customer demand is the highest. By the end of 2011, we plan to issue a request for proposal to design and construct a 500 kilowatt to 1 megawatt solar photovoltaic demonstration facility to collect information on how solar photovoltaic resources integrate with our other system resources.

We are looking to create a flexible and diversified energy portfolio to meet the demands of our customers for the next 20 years. You can find more information in the Form 10-Q filed today or view a complete copy of the 2011 IRP on our website.

And in discussing the IRP, I mentioned Langley Gulch, our gas-fired combined cycle combustion turbine. We are happy to report the project continues to be on schedule for a 2012 initial firing, and we expect total project cost to be at or below the commitment estimate.

The recent photos on slide six and seven show our progress to date. We are proud that there have been no serious injuries during the construction of this facility. The Langley Gulch power plant will provide our customers with additional base load energy that allows us to more easily integrate intermittant renewable energy sources and meet the growing needs of the region.

Finally, the J. D. Power Customer Satisfaction numbers are in. And we are proud to say that Idaho Power ranks fourth among Western mid-sized utilities. And in fact, the only utilities ranked ahead of us are non-investor owned municipal utilities. And looking at the trends, we have improved in multiple areas including power quality and reliability and customer service. We are happy to see our diligence and hard work in ensuring reliable, responsible energy for customers is showing up in our customer satisfaction scores and that our efforts to maintain financial stability have not compromised quality service.

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

Thanks, LaMont, and good afternoon, everyone. Today I will discuss the key items impacting our second quarter earnings results as compared to last year's second quarter. Our current liquidity position at IDACORP, changes to some of the key operating and financial metrics for 2011, and finish with a discussion of the uniform capitalization tax project. I'll also give you an update on our earnings guidance range for 2011. And after that, we look forward to taking your questions.

On slide eight, we present a reconciliation of net income attributable to IDACORP for the three months ended June 30, 2011 to the comparable period in 2010. This shows a decrease in net income for the comparable period of $18.3 million. Base rate changes, increased transmission revenues and changes in power supply costs, net of the related PCA mechanisms, increased operating income by approximately $11.3 million for the second quarter of 2011 relative to the prior year comparable period.

Retail sales were down slightly this quarter. The wetter, cooler temperatures that benefited sales in the first quarter continued into the second quarter. And the resulting decreased sales volumes in the second quarter reduced income by $1.1 million, largely due to a 17% decline in irrigation usage.

The revenue increases were offset by an increase in other operating and maintenance expenses of $10.3 million, primarily from greater thermal maintenance expenses and labor related charges. Of the $10.3 million increase, $5.5 million is due to increases in thermal maintenance expenses that were generally in line with expectations. An additional $1.9 million of the increase relates to increased pension expense due to incremental amortization of pension costs, concurrent with the authorization to recover these costs in revenues. This increase is earnings neutral given the corresponding increase in revenue effective with our Idaho rate order received in May 2011.

An abundance of hydroelectric and wind generation in the second quarter resulted in decreased operation of fossil fuel fired power plant including a 27% decrease in coal-fired generation at the Bridger power plants, compared to the same period last year.

Reduced production and the associated reduction in coal deliveries contributed to a $5.4 million decrease in earnings from Bridger Coal Company. We expect that increases in coal prices and deliveries in the second half of the year by Bridger Coal Company will substantially offset the current period decrease.

Idaho Power reported $2.9 million of additional amortization of accumulated deferred investment tax credits, or ADITC, in the second quarter of 2011, while the second quarter of 2010 contained a reversal of $4.5 million of additional amortization of ADITC that had been recorded in the first quarter of 2010. This represents a net benefit of $7.4 million when comparing second quarter 2011 to second quarter 2010.

Combined with ADITC recorded in the first quarter of 2011 in the amount of $3.9 million, this brings the year-to-date benefit to $6.8 million. For the full-year, we expect to record approximately $13.5 million of additional amortization of ADITC, as compared to our previous estimate of approximately $15 million that we discussed on the first quarter earnings call.

A key contributor to the change in earnings for the quarter was an increase in our other income tax expense at Idaho Power Company of $19.8 million relative to the second quarter of 2010. The increase is comprised principally of $25 million of benefits recorded in the second quarter of 2010 related to a tax accounting method change for capitalized repair expenditures that did not recur this year.

This change was partially offset by the recognition of $3.4 million of previously unrecognized tax benefits recorded in the second quarter based on the finalization of the 2009 IRS examination in April 2011 related to the same repairs project noted above.

Now I would like to turn the discussion to IDACORP's liquidity for the second quarter and year-to-date 2011. IDACORP's cash flow from operations for the first six months of 2011 was $156.9 million, a decrease of $30.3 million from the same period in the prior year. The primary contributor to the decline was changes in regulatory assets associated with the Oregon and Idaho PCA mechanism.

Changes in fuel inventory reduced cash flows by $17 million but were more than offset by cash inflows related to income taxes and the increase in pre-tax income at IDACORP relative to the same period in 2010. Key financing activities for the first six months of 2011 included Idaho Power's repayment at maturity of $120 million in first mortgage bonds in March 2011, approximately $30 million in cash dividend payment, and IDACORP's net issuance of $6.3 million of common stock under the dividend reinvestment program.

As of June 30, 2011, there were approximately 1.2 million IDACORP common shares remaining available for issuance under the continuous equity program and we did not issue any shares under this program during the quarter.

Cash and cash equivalents at the end of the first six months of 2011 totaled $58 million compared to $229 million at the end of December 31, 2010. Commercial paper outstanding at IDACORP as of June 30, 2011 was $66 million compared to $67 million at December 31, 2010.

Idaho Power Company had no commercial paper outstanding at either date. Current revolving credit facilities at IDACORP and Idaho Power are $100 million and $300 million respectively with $33.6 million available at IDACORP and $275.8 million available at Idaho Power as of June 30, 2011. We expect minimal need for external financing in 2011 at both IDACORP and Idaho Power, other than issuances under the dividend reinvestment and employee-related plans and potential issuances of IDACORP common stock pursuant to IDACORP's continuous equity program. We do, however, monitor debt market conditions and may issue debt securities when we determine that, under the circumstance and in light of the timing and extent of financing needs, conditions are favorable for issuance of such securities.

For the remainder of 2011, 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 the changes in our 2011 key operating and financial metrics. These are on slide 9. We have increased our estimated range of Idaho Power operation and maintenance expenses slightly, as a result of our expectations of slightly higher labor related expenses. A major component of the labor related expenses is increases in the amortization of pension costs that will be offset with concurrent collection of additional revenues in accordance with our May 2011 Idaho pension ruling. On an annualized basis, the increase is approximately $11 million over previous pension related amount being collected and is earnings neutral, given the corresponding increase in revenue effective with our Idaho rate order received in May 2011.

The range for capital expenditures, which includes amounts for Langley Gulch, and siting and permitting for the Boardman to Hemingway and Gateway West transmission projects, excluding AFUDC, has not changed relative to our prior guidance.

The expected hydroelectric generation range for 2011 has been updated to the range of 9.5 million megawatt hours to 10.5 million megawatt hours as compared to our previous range of 8.5 million megawatt hours to 10.5 million megawatt hours. This range now reflects actual hydroelectric generation through June and estimated ranges of hydroelectric generation for the remainder of the year. For reference, our modeled median annual hydroelectric generation is 8.6 million megawatt hours, adjusted to reflect the current level of water resource development.

Now, I'd like to review our 2011 earnings guidance. As Larry indicated earlier, we are maintaining our prior 2011 annual earnings guidance in the range of $2.80 to $2.95 per diluted share. This range includes an assumption that we would amortize approximately $13.5 million of ADITC, of which we recognized $3.9 million in the first quarter 2011 and $2.9 million in the second quarter 2011. We have up to an aggregate of $25 million available that we could recognize this year in order to attain a 9.5% return on year-end equity in the Idaho jurisdiction.

As a reminder, this guidance does not include any of the potential benefits that could result from the settlement of the uniform capitalization tax method change that I'll now discuss. With IDACORP's 2009 tax year now submitted to the joint committee, Idaho Power's uniform capitalization method agreement with the Internal Revenue Service is under review. If the joint committee approves the agreement, Idaho Power would consider the method effectively settled and will recognize approximately $60 million of its previously unrecognized tax benefits for this method in the quarter in which such approval occurs.

If approved, Idaho Power expects to increase the uniform capitalization tax deduction included in its current tax year provision as well, resulting in approximately $4 million to $6 million of additional tax benefit annually.

As we stated on the first quarter earnings call, we cannot predict when the joint committee will complete its review or the outcome of that review, but believe that the likelihood of a determination occurring in 2011 is enhanced given the case was submitted in April 2011. If Idaho Power's 2011 net income reaches the 10.5% return level as provided for in the Idaho's settlement, IDACORP's estimated earnings for 2011 would approximate $3.15 to $3.25 per share. Idaho's jurisdictional earnings beyond this level would be subject to sharing.

Idaho Power is entitled to benefit from 50% of any earnings in excess of a 10.5% return and is evaluating the potential of any such earnings in excess of 10.5% on its regulatory strategy associated with its pending general rate cases. This concludes my financial update.

Now we would like to respond to your questions.

(Operator Instructions). The first question will come from the line of Paul Ridzon, KeyBanc.

Good afternoon.

Hi, Paul.

Can you just talk about the drivers behind the lower expectations for ADITCs of $13.5 million versus the prior $15 million?

Sure, Paul. As we have talked before regarding ADITC, again that's really kind of a lever that we kind of manage -- we have the ability to manage to get to the 9.5% in the Idaho jurisdiction. So by -- based on our best estimates, we make a guess as to how much we think it's going to be. And so, as we are looking at it now, we believe that earnings would suggest that we only need $13.5 million versus the previously $15 million. So, other things moved around such that we have the ability to at least estimate to use less ADITC as we sit here today.

Is water a driver behind that?

It's really a combination of the entire business, Paul. There's nothing necessarily that's isolated to that. Obviously, the water has been a benefit now, but it hasn't been necessarily as much benefit as some might think it is other than the fact. And again most of that benefit that we do receive does go back to the customer in light of the changes in the mechanisms where we went from [90/10 to 95/5]. But really, it's really kind of overall, and when you take a look at the combined business through the six months, we're estimating that we're going to use a little bit less ADITC.

And on the GRC.

Paul, let me just -- other thing I'll just clarify too. Actually I do want to kind of focus on the O&M increase that we did increase the range for O&M, but really and you take a look at we really increased that range primarily because of the order that we received in May regarding pension. That increased pension expense was not anticipated in the original range of O&M that we had. So once we got the order that increased our ability to collect additional pension expense by about $11 million on an annualized basis, that increased the amount of O&M that we would otherwise -- we're going to incur in 2011. So that's the primary driver to why we increased the range of our O&M. The thermal O&M increase that we reported on was actually expected. It was in our original estimates for what we thought, because that -- we know the timing of when that work is done. And in this particular case that additional $5 million plus was expected. There was a little bit -- that was a little bit more than what we expected but most of that $5.5 million was expected.

And you indicated in your comments that the pension was going to be earnings neutral because there's a direct revenue offset?

Right. So we have -- revenues were increased effective June 1 to reflect now the ability to collect on an annualized basis $17 million. And so at the same time that increases, we also did increase the amortization of our pension expense. So remember, we are a little different than most folks and that we really are on a cash basis for how we recognize that expense.

Okay. That's good news. And just on the GRC, how are you thinking about the prospects for settlement. Do you think there's a good likelihood of that, do you think this needs to go the distance?

Let me just tell, first of all, yes, we have only just filed the case. And so right now the parties are in discovery, as it stands right now. And the calendar as set up by the commission suggests there are dates that are setup and couple of milestones that folks should be looking at down the road. In the normal planning process there is settlement conferences scheduled for August 31st. And if continued settlements are necessary, it's scheduled on September 8th, the staff/intervener comments are due on October 7th. So that kind of gives you a sense at least in the near term, some key milestones that are out there, as we work through the process. Right now the people are digging in and trying to understand what's in the filing. And until we get that farther down the road, we just have to wait until the calendar plays out.

And then just lastly your comments, if you're in a sharing mode in Idaho, that could impact your regulatory strategy. If you could just give a little more color as to, is that just more money to bring to the table, which could facilitate a settlement?

It's an opportunity for us -- it's a tool we could use in the event we -- we're able to get that far down the line.

Okay. Thank you very much.

Thanks, Paul.

Brian Russo, Ladenburg Thalmann.

Good afternoon.

Hi, Brian.

Just to follow-up on the last question on the -- if you're in the sharing that could be used as a tool. The ongoing benefit of the uni-cap tax study of $4 million to $6 million that -- will that get rolled up into rates as well or no, is that decision separate from earning above the 10.5%?

As we go through the rate process, everything gets reset through the regulatory process, so that -- while I'd mentioned the $4 million to $6 million, that would go into the next rate -- this next rate proceeding and be used basically to potentially offset other areas where you might see price increases. So it would eventually get included in this next regulatory proceeding.

The one that's currently pending?

Yes.

Okay. Also can you just remind us of the timing of when you're going to seek recovery for Langley Gulch?

Brian, this is Darrel. We are obviously, that is targeted or we hope to see that on line by June 1 at the earliest and our goal would be to have recovery of that coincident with the time it goes on line. So we haven't set out a specific calendar for that yet, but that would be our goal. And you might recall too the original application to just -- the original target date for that to go on line was November of 2012, and we had incentives in place with the contractor to have that project available to us prior to the summer of 2012. And so right now they are kind of working along that schedule and as we didn't -- as LaMont indicated, we are on schedule with that project as we sit here today.

All right. So you have a certain level of confidence that there won't be any sort of break lag or mismatch when the plant goes on line and when you recover the cost and rates?

I would say our goal would be to minimize any regulatory lag and that would be our goal.

Okay. And then just can you elaborate on the Boardman to Hemingway line. It appears to me that it's more reliability driven. And I'm just curious why the decision to build the line and wheel power from outside your territory which can display a lot of volatility with hydro conditions, why not just build a gas plant in your service territory?

Brian, I don't know how much time -- how much opportunity you have had to spend with the IRP. But in the IRP they go to -- spend a fair amount of time going through evaluating different options and one of the things I think that in understanding what happens with the regional economy and what happens with regional energy is that, there is a pretty good summer peaking or winter, summer peaking offsetting our region. In our particular case, we are a summer peaking enterprise, a lot of folks west of the Cascades, which is in essence where Boardman to Hemingway would be accessing, are generally winter peaking enterprises. And so there is a lot of energy available in the region at the time that we would generally need it for summer. And so that line is really being built to access that regional capacity to step in that area. And there is -- there's a lot of energy available generally at the time we need it. Today we can't bring that home today. And so that's the -- that's why you see that popping up to the top of the list in our IRP is that it does help serve our summer need, but at the same time it also -- you also mentioned reliability, and it does help our reliability but it really is to help serve our native load customers.

Understood. Thank you.

Thanks, Brian.

Jim Bellessa, D. A. Davidson & Company.

Good afternoon.

Hi, Jim.

The ADITC for the first half was $6.8 million and you're saying that you're estimating $13.5 million for the second half, that would be a total of $20.3. Up to this year under that

Jim, hold on just a second. Let me just clarify for you. We've recognized $6.8 through the first half of the year and the $13.5 million is the estimate for the entire year. So, we basically recognize 50% of what we expect to otherwise recognize for the year. And with an essence we've adopted basically somewhat of a straight-line sort of amortization of that adjusting each quarter depending on what we think the estimated annual amount is going to be. So the total --

[I appreciate] that correction.

Okay. So we've actually reduced from where we said we were going to be in the first quarter, which was $15 million estimated down to $13.5 million.

Understood. Now $13.5 million for the whole year. This is under the settlement agreement few years ago. In the two prior years you did not have to use ADITC, is that correct?

That's correct. Last year, as you recall, we were -- in the first quarter, we did recognize $4.5 million and when we recognized the tax benefit in the second quarter, we reversed that amount. So we ended up in the last -- so we didn't end up actually recognizing any. But we had started the year out anticipating we might have to recognize [somewhat a bit]. But you are correct, in both 2009, 2010 we have not recognized. At the end -- by the end of each of those years, we had not recognized any.

The $13.5 million of ADITC implies that you'll be earning in at the Idaho jurisdiction, 9.5%?

That's right.

If you did not have the $13.5 million of benefits, what would your ROE be?

I don't have that number on the top of my head, to tell you the truth. You'd have to -- I have to go do some math to kind of get to that number.

It's down in the 8s, 8% to 9%?

Yes, it would be in 8%. It'd probably somewhere between 8%, 8.5% that would be my guess.

And then why are you under earning so much in this year and why would you believe that there would be enough rate relief coming your way to be able to close that gap?

Well, that's one of the reasons we filed our case in Idaho is because obviously we are under earning. And if you -- our case suggest the $80 million plus that we're asking for is the amount that we estimate that we need and that makes an assumption to get you to a 10.5% ROE. So that's -- that is the suggestion as to why it is we're filing and that includes both recovery of current investment. We continue to add a fair amount of new investments into our system and we have also seen increases in commodity cost and price to just -- to manage the system. And so that's what's driving the $80 million plus request in front of the commission today.

If you were currently earning your ROE and all you had to do is get recovery of the Langley Gulch. How much would your rate increase have to be?

Jim, can you repeat that, sorry?

Yes, you're going to try to start recovering next year the Langley Gulch investment. If that's all you had to recover, what would the rate increase request be? What portion of the $80 million is just the Langley Gulch?

None of the $80 million is -- includes Langley. Langley, we are anticipating a separate one-off filing for Langley after we have a chance to assess that. So Langley is not included in this particular ask.

That's helpful. And then finally, in your press release you talked about the Bridger Coal Company coal prices. And you're going to try to adjust prices in the second half. How do you adjust prices, how does that happen and is that under contract when you're having losses you're able to raise the price to the customer?

Well, Jim, this is a joint-venture that we have. This is a mine-mouth facility that we have. Our plant is located at the mine and we are part owners of the mine as well as part owners of the plant. And so it's set up such that the cost of that coal is in essence set up to provide for certain return, as well as a recovering of the cost of the mining of that coal. And so there's always a reassessment of the pricing between the mine and the plant. And in part of what you saw in the first half of the year is lesser deliveries of coal, you do see some increases in cost to mine the coal. Combining all those things together, it means, there's a slight increase that's going to have to happen in order to -- in the second half of the year that will in essence recoup most of the losses or most of the decline between -- that we saw in the first half of the year. It's really set up -- it's set up Jim, to pass on really the cost of the coal plus to return into the price of the coal that gets running the plant. And that's how it's set up.

Now looking at your income statement, is this Bridger Coal Company the reason for that $4.4 million loss from earnings of unconsolidated equity method investments, is that

That's correct.

And so for the year maybe up to $5.7 for the six-months has already been realized on your income statement. You're saying, this should somehow reverse out?

Jim, you think -- if you take a look -- yes, if you take a look at our income statement, we experienced about a $3.4 million loss in the first three months. As compared to last year, we had about a $2 million benefit. So that's driving that essence that $5 million or so change. And so we would expect that that number is going to reverse in the latter part of the year, as well for the repricing of the coal, of the new coal that the plant will be taking.

Thank you, very much.

Sarah Akers, Wells Fargo.

Hi, good afternoon.

Hi, Sarah.

If I heard you correctly on the Idaho rate case calendar, it sounds like the settlement conferences are scheduled before staffing/intervener testimony is due. Is that the normal sequence of events in Idaho or is that a little different?

I'll ask, Greg Said, who is our Vice President of the Regulatory side. Can you just talk about where we're at with that.

Yes, that is normally the way it's set up.

Okay. That's helpful. And then, also can you expand on your comments earlier about potentially exploring new generation resources in the IRP, how much capacity, would we be talking about the timing and then -- would that be included in the 2013 IRP?

Sarah, in this round of IRP, what was included, the highest rated resource was access -- was basically Boardman to Hemingway by accessing resources that are already existing in the Northwest. That's the idea, our building Boardman to Hemingway is, that provides an additional access to that market, because the current ability to transport energy into our region at the time that we need it is maxed out today. And so therefore, in order to build to that area, we're not necessarily building to a resource, a specific resource, are really building just accessing that out in the Mid-C area.

Okay. So you aren't referring to new generation resources within your footprint then?

That's correct.

Okay.

This is really accessing what we believe is already there.

Got it. Thank you.

You bet.

And this is Darrel again, I want to just follow-up on Jim, your comment regarding the Bridger Coal and the reversal. The reversal, our expected reversal of that into the second half of the year is incorporated into our earnings guidance that we've -- in the range that we have in there so just to clarify that.

John Ali, Decade Capital Management.

Good afternoon, guys.

Good afternoon.

Sorry, I missed this. I joined the call late. What was your commentary regarding financing?

Our guidance there is we are not anticipating -- we are not -- we are expecting very minimal needs as we go through the balance of the year. But it doesn't preclude us either from possibly if the market conditions exist for instance on the debt side to do something we will continue to evaluate the market as through the balance of the year. We do have some refinancing that we need to do in 2012, but it's something we'll just continue to evaluate. Other than that we're anticipating minimal needs outside of our employee plan issuances under those equity plans and we still have 1.2 million shares under our continuous equity program.

All right. That's good for the next two years?

The CEP program is good through the -- towards the end of this year.

Okay, great. Thanks, guys. Appreciate it.

Thanks a lot.

(Operator Instructions). And that concludes the question-and-answer session for today. Mr. Keen, I will turn the conference back to you.

Okay. Thank you all for participating on our call this afternoon. And thank you for your interest in IDACORP. Have a good rest of your day, I know it was a tough day at the market.

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