Hawaiian Electric Industries Inc (HE) 2017 Q2 法說會逐字稿

Good day, and welcome to the Q2 2017 Hawaiian Electric Industries, Inc. Earnings Conference Call. (Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to Cliff Chen. Please go ahead.

Thank you, and welcome to HEI's Second Quarter 2017 Earnings Conference Call.

Joining me this morning are Connie Lau, HEI President and Chief Executive Officer and Chairman of the Boards of Hawaiian Electric Company and American Savings Bank; Greg Hazelton, HEI Executive Vice President and Chief Financial Officer; Alan Oshima, Hawaiian Electric Company President and Chief Executive Officer; and Rich Wacker, American Savings Bank President and Chief Executive Officer; as well as other members of senior management. Connie will provide an overview, followed by Greg who will update you on Hawaii's economy, our results for the second quarter and our outlook for the remainder of the year. Then 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 Investor Relations 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 refer to the cautionary note regarding the forward-looking statements disclosure accompanying the webcast slides, which provide 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 without limitation 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. Both our operating companies, Hawaiian Electric and American Savings Bank, delivered second quarter financial results in line with our full year expectations and our 2017 annual EPS guidance.

At the bank, we continued our strong performance through the second quarter, with higher returns from improving credit quality, higher yields and greater efficiency. Our balance sheet continued to grow, with our deposit growth, although lending was flat as our growth in consumer, home equity, residential and commercial real estate lending was offset by lower commercial lending.

At the utility, as we had previously disclosed, our 2017 results are impacted by the expiration of the 2013 settlement agreement with the Hawaii Public Utilities Commission that previously allowed Hawaiian Electric to record rate adjustment mechanism, or RAM revenue, on a calendar year basis for the years 2014, 2015 and 2016. RAM revenue now is being recorded on a May 31 fiscal year basis, concurrent with cash collections.

Overall, 2017 is a transitional year at the utility. After 6 years without rate cases and postmerger termination, we are returning to the mandatory triennial rate case cycle under our state's decoupling framework, where one of each of our 3 utilities is in a rate case test year each year, as well as working with our commission and all stakeholders in our state on Hawaii's move to a clean energy economy.

Turning to Slide 2. Our transition is progressing well. With respect to our rate case filings, we settled with the Consumer Advocate in July on all issues in the Hawaii Electric Light 2016 test rate case other than the allowed ROE. We agreed to a maximum allowed ROE of 9.75%, with the possibility of up to a 25 basis point reduction to be determined by the PUC. We expect an interim decision and order by August 21.

On July 28, the PUC issued the Hawaiian Electric 2017 test year rate case procedural schedule, with settlement discussions scheduled for the end of October and an interim decision tentatively scheduled for December 15. And on June 9, Maui Electric filed a notice of intent to apply for a general rate increase for a 2018 test year on or after August 17 but no later than December 30, 2017.

The PUC also recently approved a new recovery mechanism for major project interim recovery, or MPIR, which provides cost recoveries for projects placed in service between general rate cases under circumstances in which cost recovery, net of related benefit, is limited by the RAM cap. In addition, performance-based ratemaking moved forward in our jurisdiction, with 3 performance incentive mechanisms approved: 2 of them on reliability, with potential penalties only; and the third on customer service, both as an incentive and a penalty.

With respect to planning, in July, the Public Utilities Commission accepted our Power Supply Improvement Plan, which provides a framework to meet Hawaii's 100% renewable energy by 2045 goal. The PUC's acceptance of our plan allows us to move ahead with greater certainty on our near-term initiatives, and we will file or have filed for approval of specific projects in separate dockets.

One such project is the 20-megawatt solar facility at the West Loch Annex at Joint Base Pearl Harbor-Hickam. In June, the PUC approved Hawaiian Electric's request to build the facility at $0.0956 per kilowatt-hour or lower, which will be Hawaii's lowest-cost solar plant. This project will get us a 0.5% point closer to our 100% renewable goal on Oahu.

And in July, the PUC approved the power purchase agreement for 3 utility scale solar facilities on Oahu, with NRG Energy, totaling nearly 110 megawatts at a weighted average price of $0.108 per kilowatt-hour, including tax credits. The facilities are targeted to come online no later than the end of 2019, and would get us 3 percentage points closer to our 100% renewable goal on Oahu.

The Power Supply Improvement Plan is intended to remain flexible as technologies and circumstances change. For example, on another renewable energy purchase, the PUC recently approved the revised purchase power agreement that was filed for the 21.5-megawatt Hu Honua biomass facility on the island of Hawaii. The plant was not included in our Power Supply Improvement Plan, but is expected to add 11 percentage points to Hawaii Island's renewable portfolio standard over 2016 level to 65% renewable for the island. The Hu Honua plant will provide both capacity and energy to Hawaii Electric Light at a levelized cost of $0.221 per kilowatt-hour.

In July, the PUC denied Hawaii Electric Light's request to buy out the 60-megawatt naphtha-burning Hamakua Energy Partner's generating plant on grounds that customer benefits were not sufficiently demonstrated to justify the purchase. The HEP plant will continue to operate under their existing power purchase agreement, which expires in 2030.

Importantly, our Power Supply Improvement Plan initiative include net grid scale renewable energy procurement -- I'm sorry, not only grid scale renewable energy procurement, but also initiatives for community-based renewable energy, demand response and distributed energy resources and grid improvements.

The Hawaii Public Utilities Commission has asked us to file by March 2018, a report that details the utility planning approach and schedule for the next round of integrated planning. We are also in the final stages of finalizing a grid modernization strategy. It describes the scope and cost to modernize the energy network on the 5 islands we serve and describe how new technology will help triple private rooftop solar consistent with the Power Supply Improvement Plan and to make use of rapidly evolving solutions, including storage and advanced inverters. The first segment of the modernization is estimated at about $205 million over 6 years. The utility will continue to get feedback from customers and stakeholders as they refine their strategy for the final filing on August 29. It is important to note that all our planning now includes significant stakeholder engagement and input.

In other regulatory developments, the generators for the 15-megawatt Schofield Barracks Generating Station have just been delivered, and the project is on track to be operational in the second quarter of 2018. The plant will run on a mixture of biofuels and conventional fuels and will serve all customers on Oahu. And in the event of an emergency, can be islanded to Army facilities.

On May 19, Governor Ige appointed Jay Griffin as an Interim Commissioner to our 3-member Hawaii Public Utilities Commission. His appointment is subject to the legislature's confirmation during a special session tentatively scheduled between August 28, 2017 to September 1 of this year. Griffin is a researcher and faculty member at the Hawaii Natural Energy Institute at the University of Hawaii at Manoa and previously served as Chief of Policy and Research under former PUC Chairwoman, Mina Morita.

I'll now ask Greg to cover Hawaii's economy, our financial results and outlook for the company.

Thank you, Connie. Hawaii's tourism industry is significant driver of Hawaii's economy, continues to grow with visitor spending and arrivals year-to-date through June increasing 8.7% and 4.3%, respectively, compared to the same period last year. The state's unemployment rate remained low for the fourth month -- consecutive month at 2.7% in June 2017, lower than the prior year's rate of 3.1% and the national rate of 4.4%.

Hawaii's real estate market continued to show strength in 2017 as median sale prices for single-family residential homes and condominiums on Oahu increased 3.2% and 3.6%, respectively, year-to-date through June 2017 compared to the prior year. The median sales price for single-family homes on Oahu in June was $795,000, up 4.6% from last year.

Overall, Hawaii's economy is expected to be buoyed by the strong tourism industry. Risk remains stemming from geopolitical uncertainty and its impact on tourism and from the impact of the financial markets on real estate in development and sales.

As I review the current period results, please note that the 2017 versus 2016 quarterly and year-to-date comparisons were complicated by onetime elements materially impacting each period. 2017 reflected the loss of $14 million or approximately $0.13 per share in RAM after-tax revenues, all fully reflected in the January to May period. With the resumption of the June 1 to May 31 RAM cycle, the balance of the year will not be subject to the same continued variances created by this onetime transition. In addition, in 2016, we incurred merger-related costs of $2.7 million and $5.6 million after-tax for the quarterly and year-to-date comparable periods, respectively. Note that we eliminate merger-related cost to reflect core earnings to enhance comparability of operating results. Also, the outlook for the year is highly dependent on timely resolution of the utility's 3 rate cases after a 6-year hiatus, making 2017 a transition year to a normal rate case and RAM cycle for the utilities.

Now turning to Slide 6. Second quarter 2017 GAAP earnings per share was $0.36 compared to $0.41 per share in the second quarter of 2016. 2017 earnings of $0.36 were $0.07 lower than the 2016 core earnings, primarily due to the loss of $0.05 from the expiration of the 2013 RAM settlement agreement and $0.05 due to higher O&M expenses, including certain onetime items, partially offset by higher bank earnings.

As shown on Slide 7, HEI's GAAP consolidated ROE for the last 12 months was 12.1%, primarily due to the merger termination fee. Excluding merger-related transaction adjustments, HEI's core consolidated ROE was 8.9%, with ROE contributions of 7.2% from the utility and 10.9% from the bank. The utility ROE was impacted by the RAM settlement expiration on an LTM basis.

On Slide 8, core utility earnings were $25.6 million in the second quarter of 2017 compared to $36.6 million in the second quarter of 2016. The most significant income -- net income drivers were the $5 million in net revenues declined largely due to the expiration of the 2013 RAM settlement agreement, which recorded Oahu RAM revenues beginning January 1 for the years 2014 through 2016. The expiration of the 2013 settlement agreement had no impact on cash collections.

In addition, O&M expenses were higher by $5 million after-tax, primarily due to higher maintenance costs; higher overall expenses, largely due to timing; grid modernization consulting costs; enterprise resource planning project costs and onetime costs associated with the partial write-off of deferred geothermal RFP costs and a higher property damage reserve for a customer claim.

And finally, depreciation expense was higher by $1 million after-tax for increasing investments for customer reliability and the integration of more renewable energy.

Slide 9 shows the actual utility ROEs for the last 12 months ended on June 30, 2017. The consolidated ROE was 7.2% lower than the prior year, largely due to the expiration of the 2013 RAM settlement agreement.

On Slide 10, at the bank, net income for the second quarter of 2017 was $16.7 million, $3.4 million higher than the second quarter of 2016 and $0.9 million higher than the first quarter or linked quarter. Compared to the second quarter of 2016, the $3.4 million increase was primarily driven by $3 million after-tax higher net interest income, mainly due to growth in commercial real estate and consumer loan portfolios as well as the deployment of deposit growth into our investment portfolio. The $1 million after-tax lower provision for loan losses was offset by $1 million after-tax higher noninterest expense.

Compared to the linked quarter of 2017, the $0.9 million increase was primarily driven by the following on an after-tax basis: $1 million higher net interest income, driven mainly by higher loan portfolio yield growth in our customer loan and investment portfolios; $1 million lower provision for loan losses; and $1 million higher noninterest income, mainly due to improved performance from our bank-owned life insurance investments. These increases were offset by $2 million after-tax higher noninterest expense, primarily due to higher compensation and benefit costs.

Turning to Slide 11. American continued to deliver strong and consistent performance in the second quarter. We achieved a return on assets of 102 basis points for the quarter, above our target of 90 basis points. Our net interest margin was 3.68%, higher than our guidance range due to higher investment portfolio yields and growth of our higher yielding consumer and real estate portfolios. Overall, the bank continues to maintain robust deposit growth, strong capital levels and straightforward community banking business model.

On Slide 12, examining the drivers of our 3.68% net interest margin includes -- which include our interest-earning asset yield, which was unchanged from the linked quarter; and our liability cost of 21 basis points, which increased by 1 basis point due to higher rates on certificates of deposit.

On Slide 13, total loans as of the quarter end was flat to the prior quarter, but included growth in home equity line of credit and consumer loan portfolios. We continue to focus on strengthening the asset quality of our commercial loan portfolio, which tempered the overall growth in total loans. Our deposit growth was consistently strong at 6.3% annualized year-to-date.

Low-cost deposits have funded increases in our investment portfolio and higher yields on our loans have contributed to overall higher net interest income of $1.1 million pretax compared to the linked quarter. Noninterest income of $16.2 million compared to $15.1 million in the linked quarter, primarily driven by performance on bank-owned life insurance investments.

We've continued to see improving credit quality as a result of prudent risk management capabilities and the healthy local economy. As we've said previously, our residential portfolio remains very clean, consumer unsecured credit quality is in line with expectations for the year, and the commercial and real estate portfolios are stable with improving trends.

Provision for loan losses was $1.1 million lower than the linked quarter, primarily due to improved credit quality.

Our net charge-off ratio was 21 basis points for the second quarter of 2017, 8 basis points lower than the linked or first quarter. Nonaccrual loans, as a percentage of total loans receivable held for investment, was 0.44% compared to 0.41% at the end of the linked quarter. The allowance for loan losses was 1.19% of outstanding loans at $56 million for the quarter end, unchanged from the 1.19% at the end of the linked quarter and 1.16% as of the second quarter of the prior year.

Slide 15 illustrates American's continued attractive asset and funding mix relative to our peer banks. American's June 30, 2017, balance sheet is -- compared to the last complete available dataset for our peers, which is as of March 31, 2017. 100% of our loan portfolio was funded with low-cost core deposits versus an aggregate of our peer banks at 87%. Year-to-date, total deposits increased by $175 million or 6.3% annualized while maintaining a very low cost of funds of 21 basis points, 28 basis points lower than the median for our peers.

In the second quarter 2017, American paid $9.4 million in dividends to HEI, and American remains well capitalized at June 30, with a leverage ratio of 8.5%, tangible common equity to tangible assets ratio of 7.9% and a total capital ratio of 13.7%.

Turning to Slide 16. We are reducing our 2017 CapEx estimate to $420 million, which now includes the Hamakua Energy Partners plant purchase denial due to the -- purchase due to the recent PUC denial of the asset purchase agreement. This is partially offset by adjusting for other additional capital expenditures for the remainder of the year. The revised rate base growth is now estimated to be 3% to 4%.

Our 2018 and 2019 CapEx estimates remain unchanged and will be updated as part of our normal update in the fourth quarter webcast expected in February 2018.

As a result of the utility reducing our 2017 CapEx estimate, the utility equity requirement from HEI has also been reduced to $30 million, as shown on the slide above. As we've indicated in our fourth quarter 2016 earnings call, we do not expect any need for additional external equity, including from our dividend reinvestment plan through 2018.

We are reaffirming HEI's 2017 earnings guidance range of $1.55 to $1.70 per share. For the utility, we're now guiding towards the lower end of the utility EPS range due to several factors: the denial of the HEP purchase; Hawaiian Electric Light's settlement agreement with the CA; a slight delay in the Hawaiian Electric 2017 test year interim decision; and year-to-date actual performance, which was impacted by certain onetime expenses. However, the utility is looking for opportunities for cost reductions to mitigate these items.

The bank, however, is expecting to be at the higher end of its guidance range, with an ROA expected to be greater than the 90 basis points based upon its year-to-date actual results and growing net interest income benefiting from higher yields in mid-single-digit earning asset growth and improved credit quality. Overall, our HEI consolidated guidance range remains unchanged.

Connie, back to you.

Thanks, Greg. In summary, our utility will continue expansion of our renewable energy portfolio and grid modernization efforts to increase our resilience, reliability and promoting sustainable communities while working towards achieving Hawaii's 100% renewable energy goal. And we are actively involved in discussions to encourage electrification within our state to help us achieve a broader clean energy vision for Hawaii.

Our bank will continue to focus on deepening customer relationship to drive balance sheet and income growth.

On Tuesday, our board maintained our quarterly dividend of $0.31 per share, continuing our uninterrupted dividend payment since 1901. The dividend yield continues to be attractive at 3.75% as of yesterday's market close. HEI, Hawaiian Electric and American Savings Bank will continue to move forward providing long-term value for our customers, communities, employees and shareholders.

And now we look forward to answering your questions.

(Operator Instructions) Our first question comes from Greg Gordon with Evercore ISI.

Connie, as usual, you have a lot going on. Iron's in the fire on the regulatory front, so a couple of questions there just to synthesize what you said. The current CapEx forecast and the rate base forecast that results from that, which is shown on Page 16, what -- as we go through the course of the next 12 months of regulatory activity, what are the things that could change that could either increase or decrease the CapEx forecast? Some of the things that I noticed are, you're asking for approval for more grid modernization spending but you've also got some other large projects pending approval. So if you could try to synthesize what the puts and takes might be over the next 12 months for us, that would be helpful.

Sure. Let me give you an overall comment and then I'll ask Tayne to give you more detail. Greg, if you remember, we had originally said that we were expecting, over this time frame, roughly between $400 million to $500 million of capital expenditures annually as we move through Hawaii's transformation to a clean energy economy. And so that's really kind of the range that we continue to expect. And as you know, there's actually lots of projects that we have talked about. And so in any particular given year, some projects may move in, some projects may move out. Much as Greg commented about the HEP purchase, we were denied in making that. But there are other capital expenditures that we are making to offset that denial. So let me ask Tayne at this moment to comment a little bit further on that.

Okay. Thanks, Connie. Greg, the other things that we have in process in terms of major projects are really noted on that slide. We've got the Schofield Generating Station project, along with a Joint Base Pearl Harbor PV project, and then the third item, we're embarking on our enterprise resource planning software project there. And those 3 projects all have been approved by the Public Utilities Commission and are slated to be completed in the 2018 time frame. Adding on to what Connie said on the Power Supply Improvement Plan, which was accepted by the PUC, it provides a framework for initiatives and projects that we will be working on. We do need to file PUC applications for those major projects. And some other things we do anticipate coming up very shortly would be applications for batteries at all 3 companies as well as some of the core T&D asset management strategies that go along with our Power Supply Improvement Plan. I do want to note that our grid modernization expenditures, they do need to be incorporated within our budget, and we will be doing so and reprioritizing work. And that new forecast will be coming out as part of our year-end 2014 -- 2017 year-end webcast expected for February of next year.

Okay. So whatever develops on the Power Supply Improvement Plan front in terms of projects that get into the queue there and the integration of the grid modernization strategy expenditures sort of things that might move into the plan, other things might move out, but you're sticking with your view that the range of spending would still be in the one you're -- in the 4 to 5 -- was it $400 million to $500 million that you articulated?

That's correct. $400 million to $500 million, yes. And Greg, I would add, part of the other reason for that is when you look at the Power Supply Improvement Plan, today's energy landscape now includes a lot of other players. And so just as I noted in our prepared remarks that we're getting 109 megawatts from 3 NRG solar plants and also now an additional 21.5 megawatts from the Hu Honua biomass plant. A lot of the Power Supply Improvement Plans also covers third-party investments, not just the utilities.

Understood, understood. And when you talk about the earnings guidance ranges, you talked about being at a -- turning towards the high end at the bank, having some near-term pressures at the utility and then you also footnote that your holding company expenses should be between $0.13 and $0.15. Are you sort of trying to tell us that you're trending towards the low end of the utility guidance range at this point? And that's how we should think about things as we go into the end of the year?

Well, based on -- this is Greg, Greg. Based on the -- where we're at on a year-to-date basis, the -- we have mentioned some of the headwinds on the O&M side created by a number of onetime charges. So that put us slightly behind plan on a year-to-date basis. As we look forward, the main driver, I think, overall of where we line up within the guidance range will be the timing of the interim rate results, which is -- and that timing for interim rates on the Hawaiian Electric rate case, which is the major rate case, has now been determined just very recently, tentatively, as mid-December. So that will -- that rate relief within 2017 will be helpful, although may not be fully what we expected when we -- the timing may not be fully what we expected when we originally set the guidance range. I would say that we're in internal discussions of finding ways to offset those increased costs as well as the timing on the settlement of the rate case. So more to come on that front. But I would say, it would -- the pressures that we're seeing right now put us slightly towards the lower end of the range.

Got you. Final question, you do give lots of good insight into earned returns here and you give a GAAP ROE for the 12-month trailing basis at the utilities overall and then for each subsidiary relative to your allowed. But you haven't -- and then you also had a separate slide in the appendix where you show sort of what the structural or regulatory lag looked like in 2016. Can you give us some sense of what your aspiration is for earned ROE as we exit 2017, given the 2018 and beyond and we get past these RAM issues and these timing issues? Is there still an expectation that there'll be sort of a structural regulatory lag that's sort of pretty difficult to offset, but we should expect some sort of an aspiration at a level -- at a certain level? In the past, you've sort of given guidance around that front.

Yes, it's in -- maybe a couple of comments here and then Tayne can contribute as well. First of all, our actuals for year-to-date was impacted by the denial of HEP, which cost -- that was an $85 million anticipated purchase equitized at roughly 56%, which we anticipated to be around the timing of the first quarter in our original guidance. So you have that impacted this year, which impacted ROE expectations. Secondly, the $14 million loss on the RAM on an actuals to actual basis, all of which has been incurred now because of that onetime transition. $14 million over our equity invested into the utility will get you -- you can do the math on that. It's just $14 million net income will get you somewhere around 70 to 75 basis point reduction in what we've achieved year-to-date. So you make adjustments for that for the current period. Looking forward, the purpose of slide 2016 -- or the 2016 consolidated ROE lag was to show -- to demonstrate largely what the structural issues are that are embedded in our rate structure generally. And that 50, 60 basis point lag, it tends to be structural and not something that's likely to be recoverable through the rate case cycle. But as you look to the right on that slide, past the structural items, you see -- we demonstrated, if in 2016, had we been able to recover our full cost of service and return on our investments, that would've made 120 basis points differential. Meaning that's the opportunity that we see as we go through our first rate case cycle in 6 years to true-up the decoupling mechanisms and go through a standard rate case cycle. That's the upside. That's the opportunity that we see to improve our performance through a full recovery of our cost of our allowed cost at our allowed rates.

Our next question comes from Chris Turnure with JPMorgan.

Connie and Greg, I wanted to just clarify first on HELCO. The settlement is in regard to interim rates, not the entire case, is that correct?

Yes. Yes, it is the entire case.

Okay. And then you do put some details on the slides there, but can you maybe highlight anything that is a little bit short of maybe what you had originally expected or anything there that differs from kind of your base case expectation assuming that your ask was pretty far off from that?

Yes, I'm going to ask Alan Oshima, who heads our utilities, to comment for you.

As with any settlement, there is puts and takes. And our original revenue requirement request was around $19 million and the settlement would get anywhere from $10 million to $11 million in revenue adjustment. So individual line items, we can't get into the settlement is pending before the PUC. So but it is on file.

And that original request included in requested ROE at 10.6%. And as I mentioned, this settlement is at 9.75% with the potential for a decrease of up to an additional 25 basis points, primarily related to the decoupling.

And I would add that in the Hawaii Electric Light rate case, we -- with the consumer advocates, we have agreed to all of the issues in the preceding with the exception of what Connie stated on ROE.

Okay. Great. And then sorry if I missed this, but can you remind me of the timing there and ultimate implementation date kind of best-case scenario?

The decision is expected on August 21. And so then thereafter, I don't know, maybe 30 days to implement the rates -- file the tariffs and begin the cash collection.

Okay, great. And then transitioning to just O&M expenses, you touched on things a bit in the last question. But if I look at the test years of this case and your HELCO case as well, I would think that the only test year that applies to 2017 at least is for one of the cases. So is it possible that you could kind of be a little bit more disciplined on the O&M side here in the second half of the year? Or has something kind of been running ahead of plan on that front in particular year-to-date?

What we're doing is, as Greg mentioned, we are taking a look at opportunities to mitigate some of the matters related to a delay -- a possible delay, in the Hawaiian Electric rate case. So there are some opportunities but we are in the 2017 test year for Hawaiian Electric Company as well.

And is there a true-up for that, actual versus planned?

No, not for the -- whatever the test year is, that is what is being adjudicated. And that is what would go into interim and then final base rates. And there is no adjustment for actual within that test year, although obviously, the commission always takes a look at what actual results look like, but there is no mechanism for that actual true-up.

Sure. And that's the biggest case by far of the 3 too?

Yes. And I -- just to clarify, the HELCO case that we're settling where we expect the decision on August 21 was on the 2016 test year. And then it is, as you say, the largest utility is this year on the 2017 test year.

Our next question comes from Charles Fishman with MorningStar.

If I go back to Slide 22 in the appendix, and Greg, you talked about items 4 through 8. Are any of those being -- pending in the current pending rate cases, or any of those items included as far as providing some benefit?

Yes. They all are being adjudicated as part of the rate case. The interest rate savings for lower cost debt that we issued is embedded into our cost of capital. The pension assets -- the prepaid pension assets that we've contributed, there is some mechanism for full recovery of that investment as well as true-up so that we're fully collecting on a real-time basis our true net periodic pension cost. So that will provide cash flow relief, not necessarily earnings relief, but cash flow relief. The earnings release comes off of the recovery of the cash we've invested, which is not currently earning a return so you see that on item 6. The O&M in excess of the RAM -- the RAM mechanism, the interim mechanism, which was intended to keep us whole for inflationary cost and investments between rate cases, had a cap implemented to that. And so to the extent that costs and investments exceed those levels, we have some exposure that is being trued up. And remember, we've been relying on those RAM mechanisms now for 6 years, much longer than was originally planned, so those -- that will get trued up. And then the plant additions that were over the RAM cap, those have been put into the rate base calculations included for settlement here within the rate case cycle. So we view everything to the right of that, the first 3 items, as issues that are being addressed through these current rate case cycles. And there is the opportunity to close that significant gap between our allowed and what we actually achieve.

So you get past the cycle of rate cases? I mean, are -- and then you get to your regular cycle, 3 years on each utility?

Yes.

Do some of these take care of themselves? I mean, there's not necessarily trackers, but are there -- should we work -- will you work your way to that 120 basis point lag by the time you get to the next round or some of that be dealt with in these filings?

Remember, they're dealt with. This is -- they're dealt with on a utility-by-utility basis. So all -- each of the 3 utilities has some element of each of these lag items within the rate case. The rate case should be a full reset in terms of what our O&M recovery is, our return on rate base, an adjustment of our ROE. What's not indicated on here, this is looking historically at the historically allowed, so the ROE -- allowed ROE will be reset as well. That creates the cap on ultimately what we're likely to achieve at the high end. But all of these other items should be trued up as we come out of the rate case cycle. And then to the extent that there is deviation as we go forward, we make incremental investments between a -- the settled rate case and the up -- and each year as we go out, we make the investment, the RAM mechanism, so this decoupling mechanism should keep us whole between the rate case cycles, the triennial rate case cycle at each utility. Does that -- did that answer your question?

Yes, but I mean, going from 3 years to 6 years is going to help this lag too, quite a bit?

Yes.

Tremendously. Yes. But this should get us -- this should reset base rates that give us recovery on a settled basis of all of the -- our O&M -- our agreed-upon O&M cost, our rate base investments that are included in that rate base at our allowed ROE. So that -- we should be coming out of this with that reset. But further with all of the decoupling mechanisms going forward that also provide benefit in between rate cases at each of the utilities.

And Greg, I would also add we -- with the commission's establishment of that major project interim recovery mechanism, it has -- there is a mechanism to recover costs for major projects in between rate cases. So Charles, if you look at Slide 22, where it says plant adds over the RAM cap, that new major project interim recovery mechanism is intended to address that issue in between rate cases as well.

I want to mention though that all of this is in the context of the Power Supply Improvement Plan, the grid modernization plan, which is all intended to have the utility work in collaboration with all the stakeholders towards the state's policy, getting us to a renewable energy future with customer benefit.

(Operator Instructions) Our next question comes from Paul Patterson with Glenrock Associates.

So very quickly on the loan loss provision and the credit quality. What was driving the credit quality improvement? Was it real estate prices or anything else?

Thank you, Paul. Rich always loves the question on the bank.

Yes, Paul, we've been working through some of the higher-risk exposures we had, particularly around the leverage lending and national book. And those are the areas that we just decided at this part of the cycle we wanted a bit less exposure to. A couple of larger exposures locally on the commercial real estate side that have -- we've worked through and got paid off and that's it. It's been sort of a combination of some specific local exposures and then that national leverage lending exposure.

Okay, great. And then on the PSIP approval. And, I guess, sort of following up on Greg's question, and I think you may have answered it, but I just didn't -- I wasn't completely paying attention, I guess. When you mentioned about revising your CapEx forecast, I think providing that in February next year, does that include what you currently -- I mean, should we think of there being a significant revision to that CapEx forecast due to the PSIP approval?

No. As I mentioned before, we are looking at that range as $400 million to $500 million on a go forward basis. And we've kind of been obviously thinking about that number as we've gone through working through the Power Supply Improvement Plan and also the grid modernization strategy.

Again, it's driven by those plans and state policy and customer benefit.

Right. Now I thought when I read it and tell me if it's different, but you obviously have a better interpretation or perhaps than I do, but it seemed like it was a pretty positive order. The one thing that I thought was a little bit, that they raised an issue of was the rate impact over time with customers. And I was just wondering, a, how did you feel about the PSIP order that came out? But also just about that specific issue, what do you think about the potential rate impact? Or what should we think about that given the obvious sensitivity to it, which I'm sure you guys are -- I know you guys are very focused on? So can you just address those 2 -- the general issue of the order and also just that specific issue?

Thank you. Alan here. Yes, we're pleased at the acceptance of the plan that was done, as you know, over a long time, but including a lot of stakeholders and community input. Contrary to some interpretations, the commission did not reject things in the order nor approve things in the order. And those open items that might contribute to additional costs are still subject to our application with community input and a full hearing. So the -- it's our obligation to provide information as to customer rate impact. And so we did that from a very conservative standpoint. We are very aware of the issue (inaudible) commission and other stakeholders. We have to work on the mitigating alternatives, and there are many. And we will be working through that with the stakeholders and the regulators as we move forward. If you look at the drivers for our rates in isolated island grids, a lot of it is due to imported fossil fuel costs, which we're trying to get off of. Those things don't change immediately, however, as we transition. So there are many things that we're looking at. And I think as this process moves forward, there'll be a robust discussion around all of these issues.

Okay. In terms of just the near-term action plan and this concern about the affordability, that section of it, do you feel that, like -- I mean, obviously you're going to be addressing it and what have you. But do you feel that, that may slow down the CapEx? Or in other words, I mean, what should we think about in terms of, at least, in the near term, potential issues associated with rate impact? You mentioned the fossil fuel offset, but is there anything else we should think about that might be mitigating the cost?

Nothing that I can really discuss with you now because we really do have to include all of our stakeholders. We have thoughts and I'm sure others have as well. But you'll be hearing more about it as we implement the PSIP, but there are ways. I also want to be clear though that this transition comes at a cost.

This concludes our question-and-answer session. I would like to turn the conference back over to Cliff Chen for any closing remarks.

Thank you, Brandon, and thank you for all the participants on the call. Have a good afternoon.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.