Hawaiian Electric Industries Inc (HE) 2016 Q4 法說會逐字稿

Welcome, everyone, to the fourth-quarter 2016 Hawaiian Electric Industries Inc. earnings conference call. All participants will be in listen-only mode.

(Operator Instructions)

After today's presentation, there will be an opportunity to ask questions.

(Operator Instructions)

Please note, this event is being recorded. I would now like to turn the conference over to Cliff Chen, Treasurer and Manager of Investor Relations and Strategic Planning. Please go ahead.

Thank you, Amy, and thank you, all. Welcome to Hawaiian Electric Industries' 2016 fourth-quarter and year-end earnings 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; Jim Ajello, 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 Jim, who will update you on Hawaii's economy and our results for the fourth-quarter and year-end 2016, and our 2017 earnings guidance. Then we will conclude with questions and answers.

At 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. These refer to the forward-looking statements disclosure accompanying the webcast slides, which provide additional information on other corporate 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, and also happy Valentine's Day. In 2016, our operating Companies, Hawaiian Electric and American Savings Bank, delivered earnings within our increased 2016 EPS guidance, issued in our third-quarter call. At the Utility, Hawaiian Electric spent approximately $318 million in 2016 on local infrastructure projects to modernize and improve Hawaii's electric grid, and to reliably integrate more renewable energy.

We achieved an energy portfolio powered by about 25% renewable resources, advancing towards our 100% goal for 2045. We filed an updated power supply improvement plan in December and we are focused on creating, at a reasonable cost and working with third-party energy developers and providers, the renewable energy platform of the future for the benefit of all of Hawaii. At the Bank, we saw excellent deposit growth, higher net interest income and strong efficiency improvement.

Although provisions for loan losses increased from 2015 levels, American Savings Bank grew bottom-line earnings and maintained healthy capital levels. Following the termination of the proposed merger with NextEra Energy, and cancellation of the related spinoff of American Savings Bank, HEI and its operating subsidiaries are moving forward as an independent consolidated enterprise, providing essential electricity and banking services for Hawaii, and investing in the growth of Hawaii's economy.

Hawaiian Electric continues to be a national leader in clean energy. In 2016, approximately 25% of our combined customers' energy needs on all the islands we serve were powered by renewable resources, with higher percentages from Maui County and Hawaii island of 36% and 53%, respectively. To provide you with greater perspective, at certain times of the year in 2016, renewable sources from our grid have powered up to approximately 45% of the electricity needs on Oahu, and up to approximately 60% on Maui and Hawaii island. We are well on our way toward exceeding the next renewable portfolio standard goal of 30% by 2020.

Turning to recent utility developments. In collaboration with local stakeholders on December 23, we filed updated power supply improvement plans, which outlined a detailed five-year plan charting the near-term actions that will provide a foundation to meet Hawaii's 100% renewable goal by 2045. And we will be filing our statement of position later today.

Using a varied renewable energy portfolio, by 2020 the plan aims to achieve an RPS on Molokai of 100%; Hawaii island, 80%; Maui, 63%; Lanai, 59%; and Oahu, 40%, for a consolidated RPS of 48%, exceeding the 2020 RPS target of 30%. As a reminder, Hawaii Electric Light filed its 2016 rate case in September for a 6.5% base rate increase of $19.3 million. Public hearings were held by the PUC on Hawaii island December 13 and December 14, and we have been responding to information requests and expect an interim decision by the third quarter.

On December 16, Hawaiian Electric filed its 2017 test year rate case application. The request includes a proposed 10.6% ROE and a 6.9% base rate increase request of $106.4 million. Like Hawaii Electric Light, this is the first proposed base rate increase in six years, and will be used to pay for system upgrades and higher operating costs for reliability advances, customer service improvements, pension true-ups and renewable energy integration. An interim decision on the Oahu rate case is expected within 10 to 11 months, and a public hearing will be held February 22. And Maui Electric is expected to file its 2018 test year rate case this summer.

In other developments, because siting can be critical to the success of renewable energy projects on islands where land is limited, and also treasured by our local population, in December 2016 the Hawaiian Electric companies launched an effort to gather information from landowners about land that may be made available for future renewable projects, and issued a request for information for properties on Oahu, Hawaii island, Maui, Molokai, and Lanai, available for utility scale renewable energy projects, such as solar and wind farms, or biofuel farms.

The 27.6-megawatt Waianae Solar project, owned and operated by Eurus Energy, went into service on Oahu in January 2017. On January 31, 2017, Hawaiian Electric submitted to the PUC power purchase agreements for two Utility-Scale Solar facilities on Oahu. Both contracts are with NRG Energy, which acquired the projects following SunEdison's bankruptcy last year.

Under the agreement, Hawaiian Electric would purchase power from the 14.7-megawatt Lanikuhana Solar project for $0.0114 per kilowatt hour, and the 45.9-megawatt YPO Solar project, which would be the state's largest for $0.0104 per kilowatt hour. And these prices include our Hawaii state tax credit.

Cancelling the SunEdison contracts prior to their bankruptcy allowed Hawaiian Electric to renegotiate with successor NRG on behalf of our rate payers, to achieve prices up to 20% lower than contracted with SunEdison. Hawaiian Electric is also working with NRG on a PPA for a 49-megawatt Kawailoa Solar facility, also on Oahu. All three projects, which are targeted to come online in 2019, would get us 3 percentage points closer to our 100% renewable goal on Oahu.

Our utility has also been very aggressive in leading the way on electrification of transportation in our state. That's because our utilities only consume about one-third of the fossil fuel brought into the state. Two-thirds is used for transportation. So, if Hawaii really wants to go green and clean, we need to address the transportation sector as well.

Our power supply improvement plans include action plans for the electrification of transportation, further reducing the use of fossil fuels for ground transportation and contributing to a lower carbon footprint. Hawaii is second in the nation in per-capita electric vehicle registration.

On grid modernization, in January 2017, the PUC dismissed the Company's smart grid application without prejudice, and directed the Company to submit a detailed grid modernization strategy for each utility. The utilities must submit a detailed plan by June 30, 2017. The PUC reaffirmed the need for a modern electric grid, as we build towards a 100% renewable future and stressed the need for stakeholder involvement in developing this strategy. So, this will be a collaborative process that may resemble the work that went into our power supply improvement plan.

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

Thanks, Connie. Hawaii's tourism industry set new records in 2016, in both visitor spending and arrivals. Visitor expenditures increased 4.2% to $15.6 billion, and arrivals increased 3% compared to the same period last year.

State-wide unemployment fell to 2.9% in December of 2016, lowest in nearly a decade, and lower than the state's December 2015 rate of 3.3%, and the national rate of 4.7%. Hawaii's real estate activity remains strong. 2016 median sales prices for single-family residential homes and condominiums on Oahu increased 5% and 8.3%, respectively, over 2015. The median sales price for single-family homes on Oahu in December was $730,000, up 4.3% from last year.

According to the University of Hawaii's December 16 forecast, the Hawaii economy continues to perform well, with visitor tour arrivals up, lower unemployment, and a healthy construction sector. However, growth may be lower going forward with the plateauing of construction in 2018.

Real state GDP is expected to grow 2.1% in 2017. The outlook for the economy recently published on February 8, by the Department of Business Economic Development and Tourism, indicated that while expecting Hawaii's economy to continue to have positive growth in 2017 and 2018, it also expects that state GDP will grow at a lower rate than projected in its previous forecast, at 1.8% in 2017. Largely due to lower forecast on visitor expenditures.

Turning to our 2016 results on slide 6. Reading across from left to right, consolidated 2016 GAAP net income of $248.3 million included the one-time impact of $58.2 million of additional net income, due to the terminated merger fee, net of costs, including the related terminated LNG contract, and the associated cancellation of the spinoff of American Savings Bank.

Adjusted for merger and spin expenses and fees, core net income was $190.1 million in 2016. Core net income was $14.4 million higher, or plus 8%, than the prior year, driven by utility and bank earnings increases, and the holding company, which benefited from approximately $4 million related to the domestic production activities deduction or DPAD tax benefit. As HEI moved out of a federal net operating loss position, enabling the recognition of tax benefits at the holding company.

On an EPS basis, 2016 GAAP earnings per share were $2.29, compared to $1.50 in 2015. Excluding the one-time impact of the terminated merger and associated canceled spinoff of American, which together totaled $0.54 per share to net income and $0.15 per share net expense in 2015 and 2016, respectively, 2016 core earnings per share were $1.75 per share, compared to $1.65 per share in 2015.

Turning to our fourth-quarter results on slide 8. Consolidated Q4 2016 GAAP net income was $44.6 million, compared to $42.3 million in Q4 of 2015. Excluding costs for merger and spin-off expenses in the fourth quarter of 2015, core net income was $44.6 million in 2016, compared to $44.5 million in the fourth quarter of 2015.

I note that Q4 2016 is the first quarter in about two years where we did not report any core income expense effects of the terminated merger and spin. Hence, only GAAP reporting this quarter. An approximately $2 million DPAD reduction in tax benefits was recorded at the holding company in the fourth quarter of 2016. Offset by about $1 million in increases at both utility and bank.

On an EPS basis, fourth-quarter GAAP earnings per share were $0.41 and $0.39 in 2016 and 2015, respectively. Excluding the one-time impact of $0.02 per share at the holding company for merger and spin-related items in the fourth quarter of 2015, core earnings per share were $0.41 per share, both in the fourth quarter of 2016 and 2015.

As shown on slide 10, HEI's GAAP consolidated ROE for 2016 was 12.4%. Excluding the earnings impacts related to the recently-terminated merger and spin, HEI's core consolidated ROE was 9.5%. The GAAP ROE contributions were 8.1% for the utility and 10.1% for the bank. These were largely unaffected by the merger and spin expenses, which were primarily recorded in the holding company.

On slide 11, core utility earnings were $144 million in 2016, compared to $136 million in 2015. Utility EPS of $1.33 per share was within our utility guidance range of $1.28 to $1.36. The variances are shown on the slide, and I'll highlight a few.

On an after-tax basis, the most significant year-over-year net income drivers were $8 million in higher net revenues, primarily attributed to the recovery of costs for clean energy reliability and system efficiency improvements, and $6 million in lower O&M expense, primarily due to costs incurred in 2015 that did not recur in 2016. And the write-off of previously-incurred enterprise resource planning software costs and additional environmental reserves. These items were partially offset by $6 million in higher depreciation expense, resulting from increasing investments for integration and more renewable energy, improved customer reliability, and greater system efficiency.

At the Bank, net income for the year was $57 million in 2016, compared to $55 million in 2015. Bank EPS of $0.53 was well in line with our guidance range of $0.50 to $0.54. The most significant after-tax drivers of the net income increase from 2015 were $11 million in higher net interest income, driven mainly by commercial real estate and consumer loan and investment portfolio growth. These were partially offset by $6 million in higher provision for loan losses, largely related to commercial real estate and consumer lending activities. And $2 million in higher non-interest expense, primarily due to costs related to the conversion and upgrade of our e-banking platform.

Slide 12 shows the utility's actual ROEs for the year ended December 2016. The consolidated utility ROE was 8.1%, in line with the 2016 guidance of approximately 8%. The decline in the Maui Electric ROE to 8.1% from 8.5% was primarily driven from higher production and maintenance expense to overhaul generating units and to modify two generating units to lower the minimum load, thereby reducing curtailment of renewable energy.

On slide 13, you can see that American continued to deliver solid profitability metrics. We achieved a return on assets of 92 basis points for 2016, exceeding our 2016 target of 90 basis points.

2016 loan growth was primarily driven by commercial real estate and consumer loans. However, 2016 loan growth was slightly lower than our mid-single digit target, as the Bank has been strategically reducing its exposure to shared national credits, which decreased by $93 million, or 2% of total loans in 2016. 2016 net interest margin was 3.59% at the higher end of our guidance range, benefiting from higher yields on interest-earning assets and loan growth, and higher-yielding commercial real estate and consumer loan portfolios.

Our net charge-off ratio was 24 basis points. This was higher than our target, but consistent with our consumer risk-based loan growth. Our current-year charge-offs include a few specific commercial credits.

However, non-accrual loans as a percentage of total loans receivable held for investment decreased from 0.49% -- to 0.49% from 1% at the end of last year. Overall, the Bank continues to maintain its robust deposit base, strong capital levels and straightforward community banking business model.

On slide 14, our net interest margin of 3.59% in the fourth quarter of 2016 was 2 basis points higher than the linked quarter. Our interest-earning asset yield remained unchanged from the linked quarter, but our liability cost of 22 basis points decreased by 2 basis points, and we increased our low-cost core deposits and reduced higher borrowings.

On slide 15, pretax non-interest income of $67 million was $0.9 million lower than 2015. The decrease in 2016 was primarily driven by $1.1 million in lower gain on sale of real estate in 2016, as American recognized $2 million gain on sale in 2015 for the American Service Center building vacated as part of its a facilities consolidation plan. This was offset by $1 million in gain on sale of its branch in 2016.

Credit quality remains sound, as a result of prudent risk management capabilities and a healthy local economy. Our residential portfolio remains very clean. Consumer unsecured is in line with our expectations for the year. And commercial real estate portfolios are stable, with improving trends.

The 2016 net charge-off ratio of 24 basis points was higher than the 4 basis points in 2015, largely due to a few specific commercial credits, as well as growth in consumer lending. The higher provision for loan losses in 2016 of $16.8 million, compared to $6.3 million in 2015, was driven both by our growing commercial real estate and consumer portfolios, as well as reserves for specific commercial credits.

The allowance for loan losses was 1.17% of outstanding loans at $55.5 million at year end, compared to 1.24% at the end of the linked quarter, and 1.08% as of the prior year end. Coverage of non-accrual loans rose to 238% from 109% at year-end 2015, on a significant reduction of non-accrual exposures.

On slide 17, American's non-accrual loans to total loans was 0.49% at the end of the fourth-quarter 2016, compared to 1.11% at the end of the linked quarter, a decline of over $29 million. The decline was primarily due to the return of accrual status of $15 million in loans, $3 million in balances paid off, $3 million in balances charged off, and a $6 million segment of residential mortgage loans transferred to held for sale portfolio, pending pay-off by the guarantor.

Slide 18 illustrates American's continued attractive asset and funding mix, relative to our peer banks. American's December 31, 2016, balance sheet as compared to the last complete available data set for our peers, which is September 30, 2016. 100% of our loan portfolio was funded with low-cost core deposits, versus the aggregate of our peer banks at 85%.

In 2016, total deposits increased by $524 million or 10.4%, while maintaining a very low cost of funds of 23 basis points, 25 basis points lower than the median for our peers. In the fourth quarter of 2016, American paid $9 million in dividends to HEI, or $36 million in 2016. American remains well capitalized at December 31, with a leverage ratio of 8.6%, tangible common equity to tangible assets of 7.8%, and total capital ratio of 13.4%.

Turning to slide 19, the 2016 ending rate base was $2.8 billion, or 3% higher than 2015. Our 2017 utility CapEx estimate remains unchanged at $470 million, which includes the Hamakua Energy Partners or HEP plant purchase in 2017, and rate-base growth estimated to be 3% to 5%, net of bonus depreciation. As indicated previously, under the modified decoupling order, we expect about $275 million annually of plant additions recovered under the revenue adjustment mechanism cap.

Capital expenditures above this level would require specific PUC approval. In early 2017, Hawaiian Electric will be filing a PUC application, requesting the recovery of costs for the PUC-approved 50-megawatt Schofield project, via the RAM, since the Schofield project was filed prior to the new RAM cap mechanism. Construction of the facility began in October of 2016, and the project is scheduled to be completed in the first quarter of 2018.

The ERP project has been approved and is currently scheduled to be completed by December of 2018. The 2018 forecasts include a 20-megawatt solar facility at Joint Base Pearl Harbor-Hickam, subject to PUC approval, of an estimated $67 million project cost. In 2019, major projects should be comprised of projects proposed as part of the Company's PSIP filings. There were multiple scenarios presented in those plans, and we await the Commission's decision on which projects to move forward with in that time frame.

HEI starts 2017 with a strong capital structure of 56% consolidated common equity to total capitalization. We will not need any external equity nor any equity from our dividend reinvestment plan through 2018 and possibly longer. Our 2017 holding Company financing plans also assume investments in the Utility of approximately $80 million, of which $50 million relate to the proposed purchase of HEP, which is subject to PUC approval. And we expect to refinance $125 million of long-term debt at the holding company, and to issue additional debt to finance the remainder of our needs.

We are initiating HEI's 2017 earnings guidance in the range of $1.55 to $1.70 per share. We expect 2017 Utility EPS in the range of $1.17 to $1.27, and Bank EPS in the range of $0.53 to $0.56. Based on the 2017 CapEx plan, and the above 50% equity capitalization target, we do not expect the need for any external equity in 2017 and 2018, potentially longer, depending on the amount and pace of utility CapEx.

At the utility, our guidance assumes no changes to the decoupling model or other recovery mechanisms. Included in the guidance, is the expiration of the 2013 settlement agreement with the PUC that allowed Hawaiian Electric to record rate adjustment mechanism or RAM revenue from the January 1 for 2014 to 2016. However, this is expected to lower 2017 earnings by $0.13 a share, as previously disclosed.

We assume utility O&M to be 2% higher than 2016 levels, including ERP project costs. Excluding the ERP project costs, O&M is expected to be flat. Fuel efficiency should be consistent with rate case levels. We assume rate case -- base rate growth of 3% to 5%, net of bonus depreciation, based on 2017 CapEx of $470 million, including HEP, and long-term debt issuance of $60 million to support CapEx, of which $35 million is for HEP.

At the Bank, we assume lower mid-single digit loan growth. Net interest margin should be between 3.5% and 3.6%. Provision expense is expected to be in the range of $15 million to $18 million. Net charge-offs are expected to be between 18 basis points and 23 basis points. Overall, we expect Bank return on assets of approximately 90 basis points.

For clarity, I wanted to mention that we have not incorporated in our 2017 guidance any effects that may arise from the tax and regulatory changes being debated in Washington, DC, or in industry circles. Connie, I'll now turn the call back to you for closing remarks.

Thanks, Jim. In summary, our utilities will continue to provide essential electricity services for Hawaii, while advancing towards our 100% renewable goal. We remain focused on expanding customer options, and on creating, at a reasonable cost, the renewable energy platform of the future for the benefit of all of Hawaii, while maintaining the service and reliability our customers expect.

Our Bank will focus on deepening customer relationships to drive deposit and loan growth, as well as continually working towards improving operating efficiency and earnings growth. The Bank will break ground in 2017 on a new campus headquarters, which will allow consolidation of operations for greater efficiency and productivity, to help meet the metrics provided in our guidance.

On Monday, 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 3.7%, as of yesterday's market close. HEI and its unique combination of companies, Hawaiian Electric and American Savings Bank, will continue to move forward strongly as an independent Company, providing long-term value for our customers, community, employees, and shareholders.

And now, before we go to Q&A, I'm sure many of you saw our press release and 8-K this morning regarding our CFO transition. Our most favorite CFO, Jim Ajello, is going to be retiring at the end of the first quarter, and Greg Hazelton will take over for Jim as part of a long-standing succession planning process. Jim has served our Company well over the last eight years, and in fact, many of us cannot believe that it's been eight years. But he's decided to dedicate himself to family, various Company boards, and hopefully a less hectic pace. But of course, we cannot let Jim get away completely, so I'm delighted to announce that he is joining the Board of Directors and Risk Committee of American Savings Bank. Jim's service to the Company has been invaluable to me, the Board, and all of our stakeholders.

Our new CFO, Greg Hazelton, I think many of you are already familiar with Greg. He brings strong industry and corporate finance expertise, as well as public company experience, and has worked well with Jim over the last few years, leading to this point. We are truly fortunate to have this seamless transition.

And with that, we look forward to hearing your questions. I should add, the Management team said they're going to make Jim answer all the questions, since this will be his last webcast.

(Operator Instructions)

The first question comes from Andy Levi at Avon Capital Advisors.

Hey, I got the first question.

Hi, Andy.

How you doing? Jim, congratulations. I'll miss you.

Thank you, Andy. Thank you very much.

I really mean that, you've been very good to us here at Millennium. We appreciate that.

Thank you, Andy.

Just one question. On the guidance for 2017, just can you describe the $0.13 and how we should think about that longer term?

Yes. So, that is something that we filed, just to refresh on the topic, something we filed at the end of November. The utility had been working under a settlement agreement that lasted three years going back to 2013.

They applied to continue the current accrual of the RAM from January 1. That request was denied.

So, we're back to that prior mechanism, prior to 2013 settlement agreement. And so, I would include that in the numbers going forward, minus $0.13, that is.

Okay.

So Andy, that will affect 2017, but then the comparison from 2018, 2019 will be off that amount.

Right. Okay. Okay.

I wasn't aware of that. Okay.

So, that $0.13 is gone. It's almost like a new base that we grow off of, is that the way to think of it?

It's really --

It's not like a one-timer, right? Is it? Meaning that you get that $0.13 back in 2018?

No, it's just that it is a timing difference that will affect 2017. That removes the accrual of the revenues from January to June. But then when you look at a 2018 comparison, it will be exactly the same, because the accrual will start in June of 2018.

Okay. So, it's not like you catch up in 2018?

Correct. Right.

And it does not affect the cash collection from customers, because that always was starting at June. So, it was only the GAAP accrual of the revenues.

Okay. Because I had thought maybe when you had done the 8-K back when this first happened that this was, I don't want to say one-time in nature, but that part of the $0.13 was a catch-up, and then that the base was going to be higher. But what you're saying is, just to be clear, because it's important, this $117 million to $127 million is basically operating earnings, and that's what we're going to grow off of, without any catch-up on the $0.13 in 2018.

Yes. And another way to say it is that within 2017, we will lose the accrual of the first five months of revenue.

Right.

But then as you roll into 2018, because the revenue accrual will be June to May, you're going to actually have a full 12 months of revenue in 2018. So, that's why -- it's really a timing --

I'm sorry. Go ahead.

That was what I was saying, it's really a timing issue.

Okay. We'll speak offline. I'm not sure if I 100% understand.

Okay.

Thank you.

Our next question is from Greg Gordon, Evercore ISI.

Jim, congratulations. Greg, congratulations. And, Connie, the next time you're looking for another Senior Executive, give me a call.

Okay. All right.

It's cold right now in New York. I'm really thinking about a change of scenery.

Good to hear.

I'll also call you back offline on that. Because my understanding I thought was that you're losing these earnings, but then through the accruals being reset, and also through normal rate-making activity, a lot of the things that you're not collecting would get, as you go through these series of rate cases over the next few years, get hopefully baked into normal revenue requirement.

That's right.

That is correct.

That's a very good addition to our answer, and a clarification, because in the course of the new cases that will be filed, we'll have a chance to address that.

Fantastic.

And good point. It really only affects the accrual of revenues under the RAM, in between the rate cases.

Got you. I think we have it right in our model. I'll check with you offline.

The second thing was the current capital plan as you promulgated in the release, how much of that is still subject to -- of the major projects, is still pending approval, and what's the timeline for us understanding and whether that will be approved?

I'm looking at slide 19. What you see there is a couple of things.

Number one, I mentioned that up to $275 million, that's why you see that across the middle of the page in every case, are subject to the recovery under the RAM cap. Plus, you have major projects that you refer to, Schofield has been approved, ERP has been approved, Hamakua Energy projects is pending approval, and so is the Utility Scale Solar project that we proposed to build at Joint Base Pearl Harbor.

Is there a statutory timeframe or a pending case schedule in either or both of the Hamakua or Joint Base Pearl Harbor PV proceedings, in which we can know when we're going to have an answer?

There's a docket presently scheduled and has been under way for Hamakua, and procedural docket is to seek a decision in the first quarter of this year. That's been scheduled. And for Joint Base Pearl Harbor, I'll punt that to Alan.

There is no statutory requirement for a decision at any time. So, it will be processed, and we're hoping for an early decision, but we cannot promise anything.

Okay. And then final question. You knew you were going to get a tax question, so I might as well ask it first.

Basic math on the bank profitability, if the federal income tax rate were to be lowered, that would fall to the bottom line. That's a fair and simple answer, correct?

That is a simple answer, correct.

Okay. And then the other thing was, even if we don't get tax reform, there is the potential for the slimming down of some of the Dodd-Frank legislation.

Can you refresh our memory on what the impact was of certain aspects about it, like the Durbin amendment, so if that were changed or fully removed, what impact that might have on your profitability? Because I recall that it was -- created significant costs for your Bank.

You're correct in all respects. Going back for the last five years, since this amendment to Dodd-Frank was promulgated, the Durbin amendment, the Bank lost 10% of its net income, and an ROA contribution of 10 basis points. So, call it $60 million down to $6 million, call it 100 basis points down to about a 90% ROA.

And recall, that was because the consolidated assets of HEI exceeded $10 billion. So, the exchange fees have a different, if you will, rate card for institutions that have less than $10 billion than those that have $10 billion or above. So, rather unfairly for us, I would say, the legislation, which obviously didn't anticipate our particular unique structure, really counted the utility assets in the test in the Durbin amendment.

So, that is what we've been suffering with, as it were, for about five years now, and so that's where we stand. So, an adjustment in that could relieve that. I can't tell you what the prospects of that happening are.

It's like all the other things that are swirling around Washington, they're subject to a lot of speculation right now. We run scenarios all the time.

We certainly are not comfortable enough yet providing any of these changes in the corporate tax rate or the Durbin amendment or interest expense netting, because we have interest income at the Bank versus interest expense at the consolidated entity of, frankly, two to one. So, those are the things that seem to be in play, but we're watching them closely.

One more question on tax. It wasn't something when I first started writing on tax that I thought a lot about for utilities, but it turns out probably something that needs to be thought about, too. The border tax adjustment.

That's probably an added wrinkle for you being technically inside the borders, but actually pretty far away from the continent. You import almost everything. So, have you thought through, and if you haven't, forgive me for asking, what the impact to customer bills might be if you were slapped with a border tax on all the inputs into your business?

We're aware of the border tax discussion. We're starting to run scenarios on that, but we haven't pinned that down yet. I think Hawaii's, as you suggest, in a unique position of importing so much, including our own petroleum products, not only for generation here, but for a variety of the other aspects of the economy. This is an important point you make. We just can't quantify the outcomes yet.

Thank you. Again, congratulations.

Thank you.

Thanks, Greg.

The next question is from Paul Patterson at Glenrock Associates.

Aloha, and congratulations, Jim.

Thanks, Paul.

Let me just follow up on this $0.13, because I think it's important that we actually clarify this. All things being equal, would we see the $0.13 reverse itself in 2018, on an earnings basis?

Not on an earnings basis. So, I was singularly unsuccessful in getting you to understand. So, I'm going to ask Tayne to give it a shot from a different angle.

Hi, Paul. Okay. Let me try to take you through this.

So, let's take a look at 2017, just 2017 alone. What the $0.13 represents is the loss of the accrual for the period, January through May. Okay.

So, think of that. That's 2017.

As we fast forward to 2018, under the original framework of decoupling where the RAM revenues were recorded, from June 1 to May 31, so if you look at fast forward to 2018, the revenues that will be recorded would be five months from 2017, plus seven months in 2018. So, you'll get 12 months of RAM revenues in 2018. So, that's the difference between the two years, and the $0.13 represents the January-through-May accrual, where nothing is recorded.

Connie started by saying it's a timing thing. 2017 is that transition year, transitioning back to the original framework under decoupling, where we record revenues on a lagged basis, from June 1 to May of the following year.

I would just add that the Commission decision did that to align it with the cash collection from customers, which was always from June 1 to May 31 of the following year.

Okay. Bottom line is, we're not going to get a $0.13 pop, so to speak. We're not going to have a reversal in 2018.

That's correct.

Okay. Then with respect to the CapEx, I'm sorry if I'm just sort of missing this, but clearly it looks like your rate base forecast on slide 19 is increasing from what you had in the third quarter, and it's not clear to me what's driving it. I mean, it looks -- I see some changes in Schofield.

The ERP, Hamakua, the Pearl Harbor PV; all that seems to be the same. I did notice that smart grid is gone. Can you just -- is it the solar additions that you are talking about or what is it that's driving the rate base increase in 2017 and 2018, versus the third quarter?

Actually, if you look at, as Jim reported, the rate base growth in 2016 was 3%. That's our actual. And in 2017, the 3% to 5% where the growth is coming from it assumes that the Hamakua Energy partner, that plant, is in the rate base in 2017.

So, that's the biggest item there. The rest come from just your ordinary 2.75% rate base growth, year over year. The other project that Jim talked about, where we talked about Schofield and ERP, we'll be incurring CapEx in 2017, but those projects will be completed in 2018, which is why then the rate base is slated to be -- the range is slated to be a little higher.

Okay. But the rate base in 2016, 2017, 2018, is notably higher than it was, that you were projecting in the third quarter. You follow what I'm saying? And it just wasn't clear to me.

I guess we could take this offline. I'm just wondering what is it that actually has changed to make the absolute number higher in rate base than what you were forecasting for those three years in the third quarter?

Yes, so in the third quarter, there were a lot of smaller baseline projects that actually did complete this year. When we take a look at our entire year, generally speaking, we've got a lot of stormy weather in the last couple of months in the year. We were fortunate enough not to have any of those major storms.

So, we were able to complete a lot of little projects in 2016 that might have slipped to 2017. So, forecasting there, we had some discounting of completion of those projects in our third-quarter guidance.

Okay. And then just finally, the positive tax adjustment in the fourth quarter of the Holding Company of $2 million, what was that about?

The domestic production activities deduction, DPAD, or what most people call the Manufacturer's Credit. So, that's from the generation base at the utility, because the utility is still in an NOL situation. That credit was able to migrate up to the Holding Company, where we consolidated for taxes.

Just so you don't get confused, remember we did record a positive adjustment in the third quarter, and these adjustments are based on quite involved calculations on what we expect, as far as the generation of kilowatt hours by the utility itself, and so, frankly, we adjusted that calculation in the fourth quarter. So, you really have to net the third and fourth quarter together.

Okay. Great.

Thanks so much. Congratulations again, Jim.

Thank you, Paul.

The next question is from Charles Fishman at Morningstar.

Hi. Jim, I'm going to pass on getting in line for your job behind Greg, because I got to tell you, I don't envy somebody that's got to explain bank financials to a bunch of utility analyst prima donnas.

I always appreciate the patience you showed me. Wish you the best of luck.

Connie, if we go back to slide 4, I had just two questions. Electrification of transportation, I believe that's the first time I've heard you mention that.

Unless I've missed it. Is that something that's driven by Hawaii Electric Industries, or is that coming from the Commission, or is it government, or who's driving that?

So, hopefully, Charles, it isn't the first time that you heard me talk about it. Because we've actually been focusing on electrification of transportation for quite a while now, and probably are one of the utilities across the nation that have been leading in this area.

One of the key reasons for it is, if you just look at the economics of the state and the fossil fuel that is brought in to be consumed in-state, we only consume a third of that. Two-thirds of it is transportation.

And so, when our state back in 2008 entered into the Hawaii Clean Energy Initiative with us, it was to work on that first one-third that was our usage of the fossil fuel, the one-third brought into the state. But if our state truly wants to go green, then we have to figure out ways to address the transportation sector. And so, that's why we have been promoting things like our new electric rail that is coming into Hawaii, and then also very aggressively promoting electrification of transportation, in the form of electric vehicles that are brought in.

So, we are always advocating, and frankly, we have to advocate pretty hard to compete with California, where a lot of the zero emissions electric vehicles go. But as I said in the prepared remarks, on a per-capita basis, we actually are the second in the nation after California, and it's major effort for us. We actually, within the last year, have had a number of co-promotions with auto manufacturers for various specials on EV purchases or leases to our employees, and actually we have one ongoing right now to all of our customers.

All they have to do is bring their bill to the auto dealer, the one that is doing the offer currently, and they get a $10,000 rebate. So, we are aggressively pushing that.

We actually have become part of a consortium here in the state called Drive Electric Hawaii, that includes not only us and our cooperative that serves the island of Kauai, but also our state Department of Transportation, business economic development and tourism, our consumer advocate and a couple of the nonprofits that are very interested in climate change and helping to clean Hawaii's environment. And I'm going to also let Alan comment to you, because he's really been the face for a lot of our efforts here locally.

Thank you. I also want to point out that it is totally in line with the Commission's directive to the utilities to be innovative and look for solutions to benefit our customers. So, electrification on a scale in a de-coupled rate environment is really meant to be able to control the bills of our customers by finding other clean uses of clean energy.

So, it's a fuel substitution plan that benefits all of our customers' bills overall, brings value. The other part is, it's not just the electric vehicles, but we've been working very closely with our cities to see if we can electrify public transportation.

We were very actively seeking government grants to get some electric buses into Hawaii, and we will continue to do that. Finally, we were working very closely with our energy accelerator, with some of the programs and projects that they are encouraging, and we're working closely with them to find different ways to satisfy the needs of the electrification and the transportation sector, including novel ways to charge.

We're really excited about the possibilities of that, the batteries in the EVs as a storage component to the total energy picture rolling forward. Alan mentioned the electric buses and we've also been in discussions to utilize those batteries, and to work with our city and county to utilize those on the grid once they are no longer used in the transportation sector.

And of course, there's all the discussions about the batteries in EVs being used as storage devices that can shift load based on things like times of use rates, or providing for workplace charging, which would occur during the daytime hours here in Hawaii, when we have a lot of solar energy. So, it's a whole range of things that -- yes, Alan wants to add in. We could go on forever on this.

The final thing that, because it is public, as part of the transformation of our Company, we are standing up a separate group for electrification. We're in the process of standing that group up, and it will cross many, many sectors; finance, government, industry partners, et cetera, as well as marketing. So, that's part of our transformation plan, and we're actively pursuing it.

Yes, I didn't mean to imply you hadn't been doing things in this area before. Connie, maybe what I should have said was, is there anything that's happened recently that got it to the level that you've included it as a bullet point on your opening comments, and that I hadn't recalled before.

Obviously, maybe it's just a lot of things are happening that it's just all of them together, finally reached a level that's worth talking about right at the beginning. Is that a fair assessment?

Yes, and also a major focus of the Company coming out of our merger, we can go back to working on a lot of really exciting things that we are working on as a community. Because you can tell from our discussions that it can't just be about us. It has to really be a community-wide effort to look at electrifying Hawaii, and basically cleaning up Hawaii as the electric system goes to 100% renewable.

In general, is you're going to be hearing a lot more about electrification, because the auto manufacturers, bus manufacturers, have already started on all their plannings that will advance this faster than many people realize, and that's where we think our -- we have to be looking at the future, and that's why the emphasis has moved to this, as well.

Okay. Well, thank you for such a thorough answer.

Sure.

That's it. Thanks.

One of our favorite things to talk about, actually.

The next question is from Tim Winter of Gabelli.

Good morning. And congrats, Jim. You're going to be missed here at Gabelli, as well.

Thanks, Tim.

I have a big-picture question. Given the strong performance of the banks, ongoing capital needs at the utility, and you were close to spinning the Bank with the NextEra merger, what are some of the factors that are keeping you from monetizing the Bank and recycling capital back into the utility?

So, Tim, I think you know that we continually run that analysis, and our Boards have actually charged us with doing so. But in that analysis, there's many, many factors that go into that discussion, including the fact that Hawaii is a state that has a stakeholder statute. And so, we have to make sure that we consider all factors, not just the financial factors, but community-based factors in those analyses.

Having said that, we will continue to look at it, going forward. You probably know that some of the factors, obviously, have shifted recently with the run in the banks. That would do things like increase the tax bill for the Bank on a spin.

With interest rates rising, financing costs for an acquirer are going to be changing. So, there's a multitude of those of factors that we continue to look at, and our current view is that we have not seen a compelling case for our shareholders to move ahead with any different structure in the Company.

Okay. Thank you, Connie.

The next question is from Michael Goldenberg at Luminus Management.

Good afternoon. I actually have no questions. I just wanted to wish Jim good luck, and thank him for years of great service, and I appreciate how Jim was always a gentleman in all conversations. So, thank you very much, and good luck in your future endeavors.

Thank you, Michael. It's been an honor and a privilege.

Thanks, Michael.

The next question is from [Abdullah Murdy] at BlueCrest Capital.

Good afternoon.

Hi.

And, Jim, same from me. Best wishes, and thank you very much for everything over the last eight years.

Very kind. Thank you.

Couple of little housekeeping things. I was going through the balance sheet, and I want to make sure I saw it properly.

When I did a simple calculation, it looked like given the payment from NextEra and all these other things, the utility capitalization looks like it's about 58% equity right now, if I was looking at the right area, it's about $1.8 billion of equity, and you have capitalization of 3% or 1% or something like that. How is that going to work itself down over time, based on your plan, and will there be a period in time where the equity that's going to be recognized in rates will be lower than what we see on the financials, just because it's maybe somewhat elevated right now?

No, if you actually go back and look at the utility balance sheet, it has always been at around the 58% level. And if we look in the appendix slides, you will see that that matches up with the approved capital structure for the utility that has existed for many years in our rate case.

So, you'll see about 56% common, about a 1% preferred. You get close to 58%. But that's the utility.

We may have confused you when we talked about the higher equity capitalization of the Holding Company, owing to the receipt of the termination fee and the release of the special dividend fund in July of last year on the breakage of the transactions. That in turn allowed us to pay down all short-term debt.

We eliminated about $80 million of commercial paper. Hence, the equity capitalization level on a consolidated basis went up by six or seven points. That's why we're HEI level, we're about 56% now, but the utility's balance sheet, as Connie said, has been static for quite so many years.

Yes. And just to add to that, if you remember how we allocate capital within our Companies, because we have two heavily regulated enterprises, we really make sure that the capital structures for each of the operating companies match what is required in the regulation.

So, that's why, for example, on the Bank side, to talk about that for a moment, we really target a Tier 1 leverage ratio that we talk with the OCC about all the time. And there's quite a bit of analysis that goes on on the banking side to determine what the appropriate capitalization is to retain within the Bank, and that's really the same thing that goes on on the utility side.

Okay. And does that mean then over the next few years, as you said, you're not going to need to issue any equity at all, and it seems like I was looking through the sources, and you said there will be -- that the deficiency between cash flows and capital expenditures will be debt financed. How are those ratios going to move around, or will they somehow manage to stay in the same band?

Good observation. We don't need equity even our dividend reinvestment plan equity, which we ordinarily receive as perhaps a 1% dilution. So, no equity in 2017 and 2018.

We may even be able to go a little longer. It just really depends on the pace and level of CapEx approvals that the utility's able to execute.

What will happen with time is like a seesaw, that equity capitalization will reduce a little bit as debt comes in in the near term to finance the activities. We typically run at the Holding Company level about 50% equity. Right now, we're quote, unquote, over-equitized at about 56%, due to what I said earlier about the release of the special dividend fund and the receipt of the merger termination fee.

Okay. Does that mean that since you're not going to be issuing even stock for dividend reinvestment for the people who participate, that you'll be fulfilling those needs through open market purchases, and can you tell us over the course of this last year, what dividend reinvestment's been running at?

Sure. That's precisely right. There is still a very significant retail demand for the stock.

The retail holders in general constitute about 50% to 55% of the holding. So, we're very retail-held.

That program tends to be very successful, popular, as it were, really almost regardless of the price of the shares. That's been a very steady demand.

We do, through our shareholder services area that Cliff Chen runs, has satisfied that demand through open market purchases for those same investors. And so, we'll continue to do that as we go, and that tends to be supportive as well as the stock price, as you can imagine. So --

What was the gross dollars in 2016, the aggregate dollars that were covered by that plan?

$30 million.

$30 million?

We closed it in early December, actually, $30 million.

That covers three quarters, and then we switched to open market purchases in the fourth quarter.

We've been running $35 million to $40 million on a regular basis. As Connie said, last year, $30 million, three quarters.

That's what I was wondering. Thank you.

One of the other tax issues that's come up is deductibility of interest of Holding Company debt. So, can you remind me how much absolute Holding Company debt you have that would potentially fall under a qualification, what the associated interest cost is right now with that?

Yes, so with the reduction in the short-term debt, we have about $300 million of LTD outstanding, and the consolidated cost of that LTD is running just south of 3% pretax.

Okay. So, fairly modest. Okay.

Modest.

Not a big deal. One last thing. If I missed this in your opening remarks, I apologize.

But do you have any update in terms of the rooftop solar issue, in terms of either on a regulatory basis or netbacks, or however things are moving, or whether it's been resolved in some fashion, or whether it's going to be coming up in the docket. If you could just update me on that, and that's pretty much it for me. Thank you.

As you know, there has been some reform here. We're still going through a docket to see the next phase of rooftop private solar in our state. But things are moving along.

The Company is working with stakeholders to see what's possible. We have a lot of private solar in our PSIP, as you will see. It's really coming up with regulatory programs that will benefit all customers.

I'll add that at the bottom of page 3, we've got 15% of customers that have solar PV. We're up to just south of 600 megawatts there. Very substantial for a grid of our size.

You may or may not remember that it was a reform, as Alan calls it, in October of 2015, where the net energy metering program, as it was constituted, was closed, and limits were set, and a mechanism that changed the pricing for the purchase of those kilowatt hours was changed and reduced, as well. And it was a cap put on the program. So, Alan's really referring to the go-forward, what happens to that program next as the program has been subscribed and changed already.

Forgive me if I -- I thought that's what you were asking.

Yes, it was. I was just wondering what was going to happen.

I appreciate the refresher. Just wondering going forward here, what are the potential changes from where we are right now that you might see, as well.

In the future, there's aspects for more private solar, but maybe more controllability with advanced inverters, once the smart grid is actually out there, the two-way communications for distributed generation, how it all fits in with our demand-response programs, as well. So, it's a wholly-integrated plan to get to 100% renewable, not focused specifically on any specific resource.

I'd add that the power supply improvement plan that we filed does have significant room for increased private solar going forward into the future. And we do expect that that will continue to be a major component of renewable generation in Hawaii.

Okay. And again, Jim, thank you, and best wishes.

Thanks.

Before you get off, let me just go back and talk a little bit about your question on Holding Company debt and interest deductibility, because as you know, taxes are done on a consolidated basis. So, in our case, you also have to consider the fact that we do have the Bank, which has significant interest income, and of course that -- those tax discussions have been talking about netting interest income and interest expense. I just want to make sure you don't lose sight of that piece of it, as well.

Okay. Thank you very much.

The next question is from Jacque Bohlen at KBW.

Hi, everyone.

Hi, Jacque.

I'm going to give Rich a little bit of air time here.

All right.

Absolutely. Looking first at the loan portfolio, the [smick] pay downs that you had, I know that there was a large chunk of them in 3Q. Were there any more that came in 4Q, as well?

We continued throughout the year to opportunistically get out of some of the exposures. So, we continued. Probably 4Q was about $10 million of additional. So, for the year-end total, just north of $90 million.

Okay.

On a profitable basis.

We got out of all of them in 2016. All were profitable, and we got out above our basis.

Is that something that could continue into 2017?

Selectively, we don't think the decline will be anything like what you saw. We feel pretty good about where we are with what's left.

There are always prunings of the portfolio as we look at the relative risk and opportunity in the exposures, and the timing of that against new originations. So, you may see some volatility in the quarter, but not a big shift.

Okay. And then when I think about the loan growth that you've forecast for the year, are there any shifts within the portfolio composition that you see happening, or more just the general trend of focus on commercial and letting some of the residential run down a little bit?

Right. I think it will be fairly -- the composition won't shift as much as it did. You'll see probably commercial real estate come down slightly or not grow, as a lot of the big projects complete and pay off and convert either to mortgages, if they're residential units, or other permanent financing.

So, we don't expect -- we had really strong commercial real estate growth and we don't expect to see that again. So, you'll see a rebalancing there.

Okay. That's helpful.

Thank you. And then turning to the e-Banking platform that you have put in place, are there any more expenses that will come in 1Q from that?

No. We're through the conversion. We're into ongoing production mode.

We're realizing the ongoing savings on a run rate basis against where we were before. So, we have the ongoing normal course upgrades that we'll do as the platform evolves, but we're through that implementation.

Okay. And were there any one-time charges, either related to that or just in general, maybe some year-end true-ups that are in the expenses in the fourth quarter?

We always have year-end true-ups on performance compensation that comes in based on how the year is for all of our production teams and that. There's a little bit of that in there. Otherwise, the fourth quarter didn't have any meaningful one-time items.

That's a fairly good run rate going forward?

Yes.

Okay. That's helpful.

And when I look to the NIM guidance that you have, what kind of a rate outlook do you forecast? And does it include any additional increases to Fed funds?

We are baselining one more -- one bump this year on the timing. That's it.

Otherwise, we tend to not do our own. We use external forecasters and guys like you to tell us what's going to happen, because if we were smart enough about it, we'd have your job. So, we're looking at one more bump during the year on the Fed rate.

Okay. Well, thankfully mine comes from the top down from our Director of Research.

I don't have to forecast that either. And then the borrowing reduction that took place in the quarter, was the full-quarter impact felt for that, or was it a late quarter pay down?

It was a November pay down. We'll see a little of that ripple through a little bit more on the run rate.

Okay. And then just lastly, if you could provide your thoughts on mortgage banking, given the movement that we've seen in rates and what your expectations are for the coming year.

We're expecting a slight decline in production that will affect the split. We haven't yet gotten our heads around where it's going to affect more, the jumbo or the saleable.

The way we see it, rolling through, we tend to sell about 40% of our production as we work to remix the book. We're holding that flat now as we go into the year, but on lower production, so we'll see a decline in the mortgage banking income.

Thank you. That's very helpful. Jim, I pile on with everyone else in wishing you the best of luck in all the future holds for you.

Thanks, Jacque. I'm not going to be far from American. That's for sure.

I saw that.

The next question is from Ashar Khan at Verition.

Hi. How are you doing? Jim, congratulations.

I just wanted to get a little bit of flavor of what should we shoot for earning a return from these rate cases going forward in 2018? What could be the earnings impact or what ROE improvement do you think we should budget for, as we look into 2018 from the rate case actions during this year, 2017.

I'll start, Ashar. Thank you very much for your wishes.

I'll start, referring to slide 25 in the deck, which explains where we are vis-a-vis the allowed, and what, as it were, fixable of the possible matter from the rate cases. We're very early on from the rate cases, so it's really hard to describe or prejudge any of those matters that might actually occur.

But we tried to anticipate your question by showing you what is possible here, and I could probably leave it at that by showing you eight or so elements of where we stand from the 9.8%. As you know, we printed the 8.1%. So, there's quite a gap, 170 basis points.

This decomposition provides you a sense of what's possible and what is not possible, based on the current structure. The utility team is fine with that explanation.

So Jim, just going back to the slide, could you just go through these things which you have, what comes impossible and what is not in the possible camp?

Yes. Looking at items one, two and three, the possible as it were, the non-recovery items -- sorry, the impossible items are pictured on the left-hand side; non-recovery of incentive comp, short-term interest rate on the outstanding RBA balance, that was already fixed in a prior proceeding.

And this matter that we've actually been spending quite a lot of time on so far is the RAM revenue accrual delay, I'll call it, the June 1. So, those are the items on the order of 50 basis points here, identified in those three, labeled as such, 1, 2, 3, that are currently hard-wired, as it were. I'll call it that.

Proceeding to the right-hand side, the plant add-ons over the RAM cap are applied for, and can be fixed. The O&M in excess of the test year RAM, the pension assets there trued-up to test-year levels are a very important item for us, because (technical difficulty) for six years now.

Quite a long time, and so forth. So, that gives you a flavor here. I hope the slide is helpful in that regard.

So, the right-hand side are really the things that the mandatory three-year rate case basically true-up is meant to address. So, these are the things that happen during -- in between a rate case, when we only have the RAM-type adjustment mechanisms, ECAT going, and so these things can be addressed in rate cases.

Connie, unless I have missed on a slide, can we attribute, because what is the -- based on the midpoint of the utility guidance, what is the ROE that you have assumed will be in 2017?

That's contained here.

Can I speak, Jim?

Sure.

On the ROE guidance, we didn't give any guidance, because there's a lot of uncertainty with our impending rate cases. We're going through that process now. It's very difficult to determine what that ROE would be.

In 2017, if I have it correct, your rate base is going up by 3% to 5%, right? That's what you said.

And then utility earnings, if I'm right, are going down by $0.10 to $0.13. So, one would assume, unless my math is wrong, what I would like your help, is that the ROE should be somewhere in the low-7% areas, or am I wrong?

Well, let me just correct you on one thing, Ashar, is that, remember on that down $0.10, $0.13 of that is the difference in that RAM accrual, the change in the timing on the RAM accrual.

But doesn't that impact your ROE calculations, or no, that doesn't impact your ROE calculations?

It does impact our ROE calculations.

It does, right?

Right.

It does. But the point is that, given --

Doesn't that imply that the ROE has to be lower than the 8.1% that is shown in this slide 25 for 2017? It has to be in a 7% level, unless I'm doing my math wrong or conceptually wrong.

You're quite right. I would say that, however, given the puts and takes that could happen in the rate case, we didn't want to go further and speculate what could be the outcomes of the rate case that could.

I understand. I just want to understand that there is -- it seems like if you take the left and the right as you did, what was the permanent and what was the non-permanent, that these rate cases could be, if you get some reasonable decisions, they could be big earnings improver, because you are really huge under-earning your return in 2017.

You're more like a 7% ROE earner, based on the earnings forecast that you provided. I just want to make sure I have that math correct.

I could confirm that the adjustment of the $0.13 puts it in the 7% range, right? But what I can't --

I just wanted to have that. So, it's a 7% range.

Just to balance the answer, I can confirm that that would be the negative effect. What we don't know is, what are the other adjustable items coming out of the rate case. That's the imprecision right now.

Understand. Understand.

I just want to have a good sense as to what ROE we are earning in this 2017 case environment. Thank you so much, and congratulations, again.

Thanks, Ashar.

So, if there are no more questions, thank you for participating.

This conference is now concluded. Thank you for attending today's presentation. You may now disconnect.