Hawaiian Electric Industries Inc (HE) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Third Quarter 2014 Hawaiian Electric Industries Earnings Conference Call. My name is Kim, and I will be your operator for today. (Operator instructions.) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr. Cliff Chen, Manager of IR and Strategic Planning. Please proceed.

Thank you, Kim, and welcome to everyone to Hawaiian Electric Industries' third quarter 2014 earnings conference call. Joining me this morning are Connie Lau, HEI President and CEO, Jim Ajello, HEI EVP and CFO, Alan Oshima, Hawaiian Electric Company President and CEO, as well as other members of senior management. Connie will provide an overview, followed by Jim, who will update you on Hawaii's economy, our results for the quarter, and outlook for the remainder of the year. We will conclude with questions and answers.

In today's presentation, management will be using non-GAAP financial measures to describe the Company's operating performance. Our press release and webcast presentation materials, which are posted on HEI's IR website, contain additional disclosures regarding these non-GAAP measures, including reconciliations of these measures to the equivalent GAAP measures.

Forward-looking statements will also be made on today's call. Actual results could differ materially from what is described in those statements. Please reference the forward-looking statements disclosure accompanying the webcast slides, which provides additional information on important factors that could cause results to differ. The Company undertakes no obligation to publicly update or revise any forward-looking statements, including EPS guidance, whether as a result of new information, future events, or otherwise.

I'll now turn the call over to our CEO, Connie Lau.

Thank you, Cliff, and aloha to everyone.

Turning to our results, which we announced earlier today, both our utility and Bank are on track to meet 2014 earnings guidance, and are carefully managing expenses while executing on strategic initiatives. At the utility, we have been working hard to advance the plans we filed with our Commission in late August, which will help us increase renewables in our state to 65%, triple customer-sited solar power, and reduce customer bills by 20% by 2030. These plans are proving to be a good starting point for collaboration with key stakeholders to achieve our shared vision for a clean energy future for Hawaii.

At the Bank, we worked to deliver stable, profitable growth. Year-to-date loans to customers grew at an annualized rate of 5.9% while credit quality remained strong. The steady local economy helped offset the continuing headwinds of the low interest rate environment.

Some of you may have followed news coverage of the lava flow on the island of Hawaii. We have been monitoring the situation closely and are working with our customers in the affected areas. At this time, our expectations are that it will not have a material impact on utility operations, and our Bank's total loan exposure is limited and not material, as well.

I would now like to highlight the status of key proceedings at the utility. We have now filed all plans and filings required by the Commission in its April 28, 2014 orders. The Commission consolidated our August 26 power supply improvement plan filing for all three utility companies under docket 2014-183 and closed the docket to interveners on August 27. The Commission also issued 35 information requests to which we provided timely responses on October 10. The Commission has not yet ruled on the intervention motions, nor established a further procedural schedule.

On rooftop solar, Hawaii continues to lead the nation, with 11% of our customers now with rooftop solar and more waiting for interconnection. Just last week, we announced plans to clear the backlog of customers awaiting approval to interconnect their rooftop solar systems in neighborhoods with high solar penetration.

Based on the results of recent testing of solar inverters, we expect that, over the next five months, we'll be able to approve almost all of the customers who have been waiting for interconnections on these high penetration solar [serve kits] after they meet specified technical requirements, and the remainder no later than December 2015.

We are also evaluating the applicability of these solutions for future customers who apply for interconnections to help further our goal to triple distributed solar in our state by 2030. On the decoupling review proceeding, the Commission held panel hearings on October 28 and 29. The parties are to submit post-hearing opening briefs and proposed findings and conclusions three weeks after receipt of the hearings transcript, which are expected in the next few weeks. Reply briefs are due two weeks after the opening briefs.

On our RFP seeking 60 to 200 megawatts of storage to provide grid stabilization, Hawaiian Electric has narrowed the search to three finalists, all of whom have proposed battery technologies. Negotiations are now underway, and we are targeting to file storage agreements with the PUC by the first quarter of 2015, with systems in service in 2017.

On LNG, beyond the Fortis contract announcement for liquefaction capacity that we made back in August, we have selected two finalists in our RFP for containerized LNG and are completing the evaluation process. On our renewable energy waiver projects for Oahu, we completed power purchase negotiations with the developer of a 15 megawatts solar project and submitted the agreement for Commission approval on October 10. Negotiations are ongoing with the remaining six developers. The Commission has directed that purchase power agreements for these projects be filed by December 4. These projects total 226 megawatts, with an average price of less than $0.15 per kilowatt hour, substantially below our average cost of generation.

On our abbreviated 2014 test year rate case for Oahu, in which we proposed no change in base rates and rate recovery mechanisms, there have been no developments since our last webcast. Finally, we gave notice in October that we plan to file a 2015 test year rate case for Maui Electric by year-end to comply with the mandatory triennial rate case cycle established in the original decoupling docket.

I'll now ask Jim to cover Hawaii's economy and then our financial results and outlook for the Company. Jim?

Thanks, Connie. First, I'll briefly comment on Hawaii's economy. Year-to-date visitor arrivals were essentially flat, while expenditures were up 2% from last year's all-time highs and still robust after many years of strong growth. Hawaii's tourism sector is in a good position to match or break visitor arrival and spending records set in 2013. Statewide unemployment remained low at 4.2% in September 2014, with Honolulu at 4%, significantly below the national unemployment rate of 5.9%.

Hawaii real estate activity remained strong, with a 4.6% year-to-date September increase over 2013 and a median sales price for single-family homes on Oahu and a .5% increase in the number of closed sales year-to-date through September. The September 2014 Oahu median single-family home price was $678,500.

The Hawaii construction industry exhibited strong growth year-to-date through August 14 as the value of private building permit increased 18.5% over the same period in 2013. 2014 state gross domestic product was projected by the University of Hawaii Economic Research Organization to increase by 2.9%. Overall, we expect continuing growth in Hawaii's economy in 2014 supported by the continuing recovery in the construction industry and steady but slower growth in the tourism industry.

Turning to our financial results, as shown on slide five, third quarter earnings were $0.46 per diluted share in 2014 compared to $0.48 in the prior year quarter. Consolidated net income was $400,000 lower than the prior year as slightly higher utility and other segment earnings helped to offset lower Bank earnings. However, EPS was $0.02 lower than the prior year due to the increased number of shares settled through both the equity forward agreement and through our dividend reinvestment program to support the capital needs of the utilities.

As you can see on slide six, HEI's core return on equity for the last 12 months was 10.1%, with the equivalent ROE contributions from the utility at 9%, while the Bank achieved an ROE of 9.9% as it continued to maintain a conservative risk profile.

On slide seven, utility earnings were $38.9 million for the third quarter of 2014 compared to $37.8 million in the third quarter of 2013. The detailed variances are shown on the slide, and I'll just highlight a few. Utility net revenues after tax were $8 million higher than the prior year quarter, largely driven by the recovery of infrastructure investments. Operations and maintenance expense, excluding net income neutral items, after-tax were $2 million higher, or 2.3% higher compared to the prior year quarter, largely due to the following pretax items ? $4 million in consulting costs related to the regulatory filings, $4 million in storm restoration expenses, $3 million for the initial phase of our Smart Grid installations for our grid modernization program. These were partially offset by $4 million in lower customer service expenses, $2 million in lower overhauls, and $2 million in savings from the deactivation of generating units. And last year we recorded a reversal of deferred tax liabilities of $3 million related to prior years.

At the Bank, net income for the third quarter of 2014 was $13.3 million, $1.6 million higher than the linked quarter. The increase was primarily driven by higher mortgage banking and the income and higher net interest income due to higher loan balances and the recognition of interest associated with the payoff of a nonperforming commercial loan.

Compared to the same quarter of 2013, net income decreased by $2 million, primarily driven by $1 million in higher provision for loan losses as last year's provision expense was unusually low, $1 million in lower fee income on other financial products in mortgage banking income, and $1 million in net gain on a strategic sale of the credit card portfolio in the third quarter of 2013. These were partially offset by $1 million higher net interest income associated with the payoff of a single nonperforming commercial loan and higher loan balances.

Turning to the utility's ROEs on slide nine, we show the utility's actual ROEs for the last 12 months. The consolidated core ROE of 9% on an LTM basis improved from 8.1% in September 2013 primarily due to the impact of the 2013 and 2014 RAM revenues, including Hawaiian Electric's incremental 2014 RAM revenues recorded from January 2014 as well as lower O&M expense.

Turning to the Bank's metrics, on slide 11 you can see that American continue to deliver solid profitability metrics, which were generally in line with its targets and peers. We have maintained a competitive return on assets of 98 basis points year-to-date through September. Year-to-date annualized loan growth was 5.9%. In the third quarter, loan growth was driven primarily by higher commercial real estate, home equity lines of credit, and residential loans. We expect to meet our mid-single digit target for the year.

Our strong loan growth has helped offset the decline in the net interest margin. Year-to-date credit costs remained extremely low. Effective asset quality and risk management resulted in a year-to-date net charge-off ratio of one basis point, extremely attractive relative to peers. Overall, the Bank continues to maintain its low risk profile, its strong balance sheet, and its straightforward community business banking model.

On slide 12, our net interest margin of 3.62% in the third quarter of 2014 was seven basis points higher than the linked quarter. Our interest earning asset yield improved by eight basis points, attributed to multiple factors, including the interest recovery of the nonperforming loan, which contributed five bases point this quarter, with improvement in portfolio mix adding five basis points. These improvements were partially offset by lower yields of two basis points due to the ongoing effect of the continuing low rate environment. Our liability cost of 23 basis points was one basis point lower than the linked quarter, but still extremely low compared to peers.

The third quarter of 2014 noninterest income was higher than the linked quarter primarily due to higher mortgage Banking income and fee income on deposit liabilities. Mortgage banking income was higher than the linked quarter as more production was sold to maintain the targeted loan portfolio mix.

Turning to credit quality, provision for loan losses was $1.6 million in the third quarter of 2014, higher than the linked quarter of $1 million and the $100,000 in the third quarter of 2013. Provision in the third quarter of 2013 was unusually low due to the release of reserves associated with a specific commercial loan payoff and recoveries of previously charged off loans. Provision for loan losses was higher than linked quarter primarily due to a net increase in classified loans, largely driven by two commercial borrowing relationships.

Total provision was $3.6 million year-to-date. Net charge-offs of $500,000 in the third quarter as compared to a net recovery of $400,000 in the linked quarter and $6,000 in the prior year quarter. Third quarter of 2014 net charge-off ratio was four basis points compared to the four basis-point recovery in the second quarter of 2014 and nil in the prior year quarter. Year-to-date, net charge-offs were one basis point. The allowance for loan losses was 1% of outstanding loans and quarter-end, consistent with the 99 basis points from the linked quarter. Asset quality continues to be positive, reflecting the healthy local economy and strong risk management practices.

On slide 15, American's nonperforming assets ratio was 88 basis points, 17 basis points lower compared to the end of the second quarter and lower than the 1.33% at the end of the third quarter last year. The improvement reflects the payoff of a nonperforming asset in the third quarter of this year, and is consistent with our improved credit quality, effective credit management, and strong loan growth.

Slide 16 illustrates American's continued attractive asset and funding mix relative to our peer banks. American's September 30, 2014 balance sheet is stacked against the last complete available data set for our peers, which is as of June 2014. 96% of our loan portfolio was funded with low-cost core deposit versus an aggregate of our peer banks of 89%.

Year-to-date September total deposits increased by $161 million, or 4.9% annualized, the $4.5 billion driven mainly by an increase in low-cost core deposit. American remains well-capitalized at September 30, 2014, with a leverage ratio of 9.1%, tangible common equity total assets of 8.5%, and total risk-based capital of .6%. In the third quarter, American paid $8.75 million in dividends to HEI while maintaining healthy capital levels.

Turning to the 2014 outlook, we are narrowing HEI's earnings guidance range to $1.60 to $1.67 per share from $1.57 to $1.67 per share. We do not expect to have any further equity needs in 2014, and the utility has lowered its equity requirements from HEI to $40 million from $60 million in 2014 as a result of improved cash flows primarily from decreased current tax liability.

We have 4.7 million shares available to be settled under the equity forward contract, and have extended that contract approximately nine months to December 31, 2015. At the utility, based on our current year-to-date results, we are narrowing our utility EPS guidance range to $1.30 to $1.33 from $1.28 to $1.33 per share.

Although our year-to-date O&M expense is lower than the prior-year period, we are maintaining our O&M guidance of flat O&M compared to 2013 levels as lower O&M year-to-date will be made up during the fourth quarter, with continuing consulting costs associated with the regulatory filings and higher initial Smart Grid costs. However, we expect rate based on to be approximately 5% this year instead of 8% to 9% due primarily to the increase in deferred income taxes and a corresponding increase in cash flows and decrease in rate base.

We are now guiding the utility's return on average common equity to be at the higher end of the range of 8% to 8.3% due to our improved cash flows. At the Bank, although there is no change to bank EPS guidance range, we expect provision expense to be within the guidance range of $5 million to $7 million instead of at the lower end of that range that we guided last quarter due to the uncertainty related to the lava flow and our exposure in that area.

However, based on our year-to-date results, we now expect net interest margin to be at the higher end of the guidance range of 3.5% to 3.6. And at the holding company and other segment, we now expect the net loss to be $0.17 to $0.18 per share instead of $0.18 to $0.19 per share, primarily due to lower interest expense from our short- and near-term debt levels.

Connie, I'll now turn the call back to you.

Thanks, Jim. In summary, our utility has been aggressively pursuing opportunities to lower customer bills by reducing Hawaii's dependence on imported oil, integrating more cost-effective renewables, and strengthening grid reliability. We are working collaboratively with key stakeholders to achieve our shared vision for Hawaii's clean energy future, and our recently filed plans with the PUC are providing the starting point to launch important discussions and initiatives.

Our Bank continues to focus on its core banking business, targeting mid-single digit loan growth, strong credit quality, and above-average peer returns, and has been delivering on those promises. Our unique business model continues to provide HEI with the financial resources to invest in the strategic growth of the Company while supporting the continued stability of our dividend.

On Wednesday, the Board maintained the quarterly dividend of $0.31 per share. Our dividend yield continues to be attractive at 4.4% based upon Wednesday's close.

And finally, I would like to congratulate Alan Oshima, our new President and CEO of Hawaiian Electric, whom Cliff introduced at the start. Alan brings extensive energy industry experience particularly in regulatory matters, a real passion for moving Hawaii to a clean energy future, and a proven ability to bring people together to work collaboratively for needed change as a responsive and affordable energy service provider for our customers.

And with that, we look forward to hearing your questions.

(Operator instructions.) Ashar Khan, Visium.

I guess good afternoon, and congratulations on a good quarter. Just wanted to get a little perspective I guess from Alan and Connie, or from the whole group, as to the hearings that happened at the end of October and how we bring that to a closure, and any comments you can share on the new plan, or any conversations you've had on the new plan, and how does that go forward in terms of its bringing that to a closure as to when we could get something out of the Commission as to what they like and what they don't like.

Yes, certainly, Ashar. And I think the first comment I'd make with respect to the plans, is the reason we call it a starting point is because it really forms the basis for community-wide discussion for us to really work through a number of the issues, because these are really planning documents that establish a vision for the future of Hawaii.

And I think one of the things that we have always felt and is quite clear in all the discussions that we have with stakeholders is that our community is very united around the idea that people want a clean energy future for Hawaii. So there's little doubt that everybody has that same goal in mind, and as you know, it's a pretty aggressive goal in our state as our new plans are looking at moving to 65% renewable.

I know Alan is actually in California with Joe Viola, our regulatory head, and so Alan, I'll turn it to you and-or Joe, or both of you, to comment on the recent hearings.

Hi, Ashar, this is Alan Oshima. Joe is with me, and he can just briefly give you the next steps in the decoupling proceedings.

Hello. So, that's correct. We had two days of hearings with the Commission and the parties in the decoupling docket -- that's the schedule B portion of that proceeding -- on October 28 and 29. There's still a procedural portion of the docket to go. When the parties receive the transcripts of the hearings, they will have three weeks on that point to file their opening briefs and proposed conclusions and findings, and then two weeks after that date, the parties will be able to file reply briefs. The Commission has not stated when it intends to role in that docket.

Okay. And there's no chance of any kind of settlement or anything like that? We are going to go through this through a litigative process to the end?

Well, I think, Ashar, as I indicated, we are having many discussions with lots of the stakeholders. And so, the Commission is taking all the input from all of the different stakeholders into account and coming up with the decisions that they'll be coming out with. But, I think a lot of those discussions are actually just happening continually, and there aren't any particular plans for settlements outside of those kinds of discussions.

Okay. Thank you, Connie.

Charles Fishman, Morningstar.

Thank you. I was just curious, the rate base growth, you indicated it was higher deferred -- or one of the reasons was higher deferred taxes than you anticipated. Can you give any more color on that? I mean, what happened exactly?

Sure. I'm going to ask Tayne Sekimura, the CFO for the utility, to address that.

Hi, Charles. In our rate-based calculation, one of the items affected our deferred taxes, and this relates to the repairs deduction that we had taken. We also took a look at some of the other tax items in the accumulated deferred income taxes and then made adjustments. So, with the higher accumulated deferred income taxes, that brought down rate base.

So, it sounds like it was an audit of the current level, or the level on the books of deferred taxes. And then, what was the other -- the first thing you said was a -- I didn't understand that.

Well, there is a deduction. It's called the repairs deduction, and based on that particular item, it actually increased our deferred taxes, which reduced our rate base.

Okay, thank you. That was it.

(Operator instructions.) Paul Patterson, Glenrock Associates.

Aloha.

Hi, Paul, aloha.

How you doing? So, just on the repairs deduction, was there any impact on EPS?

No impact on EPS.

Okay. And then, if bonus depreciation is extended, could that impact your rate base growth assumptions?

Yes. This is Tayne. Yes, it could.

Any idea about how much it might?

Well, we don't have any idea, but if you just take a look at 2013, the impact of bonus depreciation 2013 was about $50 million of [free cash flow], just as a guide.

I'm sorry, you faded out there a little bit. I apologize. I couldn't hear very well. $50 million, you said?

Yes, impact. I'm basing it on 2013 experience, where we had the--.

--Right, I got you. Okay, just wanted to make sure I heard you. Okay. And then, with respect to the -- with respect to the PCEP, how are we in terms of -- you guys set out some goals that you had in the fourth quarter of signing the LNG contracts, submitting an application in this quarter. Is that still going to happen?

Alan, can I ask you to address that one?

Sure. Hi, Paul. We are still working on the LNG. As you know, we have narrowed the field down to two finalists, and we're still working through that, the remaining issues. We have, as you know, signed a liquefaction agreement with Fortis BC as a source of liquefaction in Vancouver. But, we're still working through the finalists and working out details, so we're not able to say with any certainty today when that will actually be signed. But, we are still targeting to be on schedule.

Okay. Now, you guys also expected to be by June 1 of next year to have all the major permits granted. Have those permits been filed? Have the application for those permits been filed?

Well, what we're looking at right now is what we call the bridge to the bridge, and it's looking at an interim source for LNG, and we're looking at potential sources and logistics that will not have a lot of permitting requirements for the delivery of LNG to our plants.

[Right], and I can appreciate that, but as you guys acknowledge in your piece, that this isn't an aggressive plan, and regulators are not always expeditious as one might hope. And I'm just wondering, when we look at this, what the outlook for the potential for slippage in this might be.

So, Paul, we [can't] speculate. It depends on what we file and how many moving parts there are. We are hopeful that what we file eventually will be compelling to our regulators, and that there may be some processes by which we can obtain the approvals that are needed.

If there is any slippage, one of the things that comes to mind is you guys are also planning this bulk LNG a few years later, and one wonders whether or not this interim sort of containerized LNG thing might be somewhat abbreviated, or maybe whether or not that might change in order to go for the bulk LNG, if you follow me.

We're pursuing both, Paul, and the interim solution may lead to a permanent solution. So, we can't really speculate at this point. We are working very hard on seeking the most reliable, cost-effective source for LNG in the timeframes that we've set forth in the plans.

Okay. I just wanted to look into that. Okay. And then, just back to the Bank for a second, I mean, there are a lot of moving parts, and I was just wondering if you could sort of -- there were some reversals and what have you, and quite frankly I wasn't able to follow each and every one of them. And I'm just wondering, without the reversals and what have you, I know that's part of the business, but how should we think about the net interest margin provision for loan losses, going forward? Do we have a -- what kind of picture do we have in terms of going forward in those areas?

So, Paul, I'm totally smiling because all of us here are, like, so happy that somebody asked a Bank question. And Heather, our Bank CFO, is dying to answer a question for you, so I'll hand this one to her.

Sure. Thank you. As Jim mentioned, we did revise our guidance for our net interest margin to the higher end of the 3.5% to 3.6% range, and that's really due to the fact we did have the interest recovery on the payoff of the nonperforming loan that Jim had mentioned. That contributed about -- just under $700,000 to net income, and also around $600,000 to interest income.

So, that enabled us to increase the range. We're still seeing our standard two to three basis point decline per quarter related just to the low interest rate environment and the roll-down of the portfolios, and we would expect that to continue. There's also some volatility introduced by FAS-91 adjustments on a quarter-over-quarter basis. And so, with all of those considerations in play, I would expect to be where Jim had mentioned, in the higher range of the [MIM] guidance.

Now, regarding provision, we had changed the guidance previously. We had $5 million to $7 million as our guidance range, and we had last quarter said we'd be at the lower end of the range based on our favorable credit statistics, lower delinquency, low net charge-offs. We would have expected to continue that guidance. However, with the uncertainty around Puna and the lava flow, we have retracted that additional statement regarding the lower end of the range in order to allow for some volatility associated with the outcome of that lava flow situation.

Yes. The lava flow thing, I'm glad you brought that up, because I'm just sort of wondering, it's kind of unique. And what if the lava flow got much worse? Should we think about how much could that -- I guess I'm wondering is how much of that risk, because of the lava flow issue in terms of your risk -- the risk scenario that you have at the Bank? Do you follow me? In other words, I mean, if it got much worse, would we have to worry about that a lot here?

And Paul, this is Connie. I'm going to ask Heather if she can maybe explain a little bit about how the loans are done and the lava insurance coverage that is on those loans so that you can get a feel for why we made the statement at the start that we don't expect the impact to be material. So, Heather?

Sure. So, essentially, when we provide loans in a lava area, there is something called a lava zone, one, two, three, four and five, depending on the risk of that particular area.

It's just like flood zone.

Like flood zones, right. And so, we have done a review of what exposure we have. Essentially it is about 100 homes that would be impacted that we have loans to. And in the Q, we actually did disclose that that's just under $13 million of exposure, mostly residential. There is one commercial property, as well.

Based on that, when we do make the loans, we do require lava insurance for zones one and two, which is where the majority of these exposures are. So, at inception of those loans, these properties were required to have lava insurance. Now, really what that entails is, if the lava were to destroy the homes specifically, then they would be eligible for reimbursement. The other item that is in play here is that there is a limited access point to the town of Puna. And so, if the lava were to cover that road and limit access, there's -- it's very uncertain of what impact that would have on the overall collateral values of those homes that we have there. The positive is that we have lower loan to value on those exposures overall, and so we do think that our total exposure is non-material, as we had mentioned.

And right now, the county is also opening up a backup access road through the Chain of Craters, so they have the bulldozers out there breaking up the lava field to open up that access road, which in prior years had actually been covered by lava. So, they're basically uncovering that old road again.

Okay. Wow. Okay, thanks so much.

Come visit us.

Andrew Weisel, Macquarie Capital.

Hi, guys, good afternoon. It's actually James Ward on Andrew's behalf. How are you?

Hi, James, how are you?

Good. On Monday, you'd indicated that you intend to clear the backlog of customers who've been waiting for interconnections to be completed. This had previously seemed to be very physically demanding and onerous. What changed to make it more feasible now? And also, what impact, if any, does this have on the filed plans for the PSIP and on your relationship with regulators?

Yes, James. As I indicated, we've been having lots of discussions with many, many parties here in Hawaii and have been working actually with the solar companies and the inverter manufacturers for quite a while. So, I'll ask Alan to update you on what the breakthrough was.

Hi, James. As Connie mentioned, we've been working with the industry and installers, but we've also been working with national labs, et cetera, to test the capabilities of the inverters to see how quickly they could respond to fluctuations. And recently, the preliminary results from those tests indicated that they could respond as quickly as we think is necessary in highly loaded circuits in order to provide some assurance that we would not experience stability or instability that would affect other customers.

So, that is what caused us to relax and start moving some of the customers who have been waiting for approvals in those highly loaded circuits towards approval. As long as the inverters can meet those standards, we can start moving the queue again. We are looking at further improvements. We're going to continue to work with inverter manufacturers and the installers to see what kinds of capabilities can be installed in Hawaii, which is leading the nation in installations of distributed generation, so that we can assure stability for the rest of our -- the 90% of our customers who rely on the grid as well, that the high influx of intermittent solar and fluctuations in the production they provide will not cause disturbances to the rest of our customer base.

Perfect. Okay, thanks, Alan. So, what impact does that have, if any, on the filed plans for the PSIP? And does this have any impact, maybe a positive benefit, as far as regulators go by showing that action on your part?

Well, it's positive for everyone, including people who are still looking to install PV. But, it does not affect our PSIPs. Our PSIPs, as you know, projected a tripling of solar up to 2030. So, we fully intend that there is room for additional distributed solar in our system as long as technology allows us to keep up with the stability issues, et cetera. So, we're going to continue to work on this. We have teams of people who are addressing this every day from a customer perspective and working with the industry and the contractors to see how we can continue to move it.

Perfect. Thank you very much.

James, I would add that the nature of the PSIPs and in (inaudible), because they go out to 2030, are in the nature of longer-range planning. And therefore, in there, we also have assumptions about what we expect as far as the cost curves for solar technologies, storage technologies, and the like. So, as Alan says, we are expecting that a lot of the cost gains that we have seen are going to continue, and we'll move from the TV area over into the storage area, as well. And so, we want to be in a position to have Hawaii benefit from all of those favorable cost curves in renewable.

Great. Thank you.

David Paz, Wolfe Research.

Good afternoon.

Hi, David.

Just a couple of housekeeping questions here. What is the base for the roughly 5% growth in rate base this year?

David, this is Tayne. Could you clarify your question?

What rate base were you assuming in 2013? What's the number, and was that an average or a year-end?

Okay, hold on just a sec while we look that up.

So, David, our average rate base for 2013 is at $2.6 billion.

$2.6 billion, okay, great. Thank you. And then, so the ADIT, or the increase in the ADIT explains the entire movement down from roughly 9%, or what it was before, to 5%? Are there any other items?

No, it was mostly the deferred taxes, David.

Okay. Great. Switching gears, any sensitivity you can give us between changes in the low sulfur fuel oil prices to the average customer bill?

Yes. This is Tayne, and I can give you some information real quickly. What we've seen is the prices, and let's just take the Oahu bill as an example. From September through October, we saw a decrease of our typical bill of about 2.3%, and then from October to November, bills, another 4.7% on top of that. So, in summary, we've seen bills in September, average bill of $219 roughly, decrease in November to about $204.

Okay, so are reductions in low sulfur fuel oil prices effectively like immediate flow-throughs to customer bills?

Yes. Well, what happens is it stays in inventory for, say, like a couple of -- a month or so, and it runs through the billing cycle. So, maybe there's about a one- to two-month delay by the time you see the prices affecting customer bills.

So, David, I mean, the good thing is, as you know, oil prices have been coming down, so we're actually expecting bills to continue to decline.

Great. Great. Okay. And then, just on your abbreviated rate case, does the 11-month statutory deadline for an interim PC decision, does that still apply for the abbreviated rate case?

I believe it does.

Okay, but there's no procedural schedule at the moment, correct?

Correct. Let me ask Alan or Joe, because, as you know, the abbreviated rate case was a new filing for us to propose to the Commission that has asked for innovative kinds of ideas. So, Joe?

So, thanks, Connie. Joe's sitting here with me, but this is Alan. Our abbreviated rate case, as Connie mentioned, is unique, and we did not ask for any approvals. We did ask if there were concerns that needed to be addressed, that we'd be happy to respond to them. And so, that's where it sits.

So, it is -- it's sort of a hybrid. We've provided as much information that we thought would normally be provided in a full rate case, but not in the form of witness testimony, with a few exceptions. But, all of the numbers and schedules that would normally be filed in a full rate case were filed. And so -- but, the unusual part of it is that we were not seeking any rate relief.

I see. Okay. Okay, great. And then, just last, Jim, can you go over again -- I'm sorry -- the rationale for extending the forward equity deal to December 15 and just how we should think about when you expect to draw down from that?

Yes, it's Jim. Thank you, David. So, the rationale was that we're virtually at the end of the year. The utility requirements this year are going to be lower by about $20 million to $40 million in equity contribution. The contract, as initially entered into in March of '13, would have expired in March of '15. Given that our equity contributions normally are seasonal in the fourth quarter of every year -- doesn't have to be that way, but that's been our custom -- is we wanted to extend the contract through the time of our next (inaudible) infusion after December of '14. We are also at the point in the year where we do our forecasting. We take a look at the utility's capital, CapEx and capital requirements and size up their rate case ratios to maintain those at the end of every year.

So, at 4.7 million shares yet to be settled, so that'll generate a little more than $100 million, we estimate that we would use that in the course of next year, and in fact by next December. So, the extension on the contract is really a nine-month extension through the end of 2015.

Got it. Okay, thank you.

Sure.

Okay, ladies and gentlemen, that concludes our question and answer session. I will now turn the conference back to Cliff for closing remarks.

Thanks again, Kim. Thank you to all the participants on the call. As usual, if there are any follow-up questions, please forward them to my office. Have a great day.

Ladies and gentlemen, that concludes today's conference. Thank you so much for your participation. You may now disconnect, and have a great day.