Hawaiian Electric Industries Inc (HE) 2013 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2013 Hawaiian Electric Industries Incorporated earnings conference call. My name is Celia, and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today Ms. Shelee Kimura, Manager, Investor Relations and Strategic Planning. Please proceed.

Thank you, Celia. And welcome, everyone, to Hawaiian Electric Industries 2013 year-end and fourth-quarter earnings conference call. Joining me this morning are Connie Lau, HEI President and Chief Executive Officer; Jim Ajello, HEI Executive Vice President and Chief Financial Officer; Dick Rosenblum, 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 of the year and an update on our strategies. Jim will then update you on the Hawaii's economy, our results for the year, and will provide 2014 earnings guidance. 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 material which are posted on our 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 reference the forward-looking statements disclosure accompanying the webcast slides, which provides additional information on important factors that could cause results to differ. The Company undertakes no obligation to publicly update or revise any forward-looking statements, including EPS guidance, whether as a result of new information, future events, or otherwise.

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

Thanks, Shelee, and aloha to everyone. 2013 was a dynamic and challenging year for Hawaiian Electric Industries. At our bank, robust loan growth and improving credit quality helped us manage through the challenges of continued low interest rate, a slowing market for mortgage refinancing, and new regulatory limits on debit interchange fees.

At our utility, we integrated renewable and customer-sited generation at levels unprecedented in the industry. These high levels of distributed renewables create many new and dynamic challenges. We are collaborating closely with our stakeholders and our regulators on possible technical business and regulatory solutions which can allow us to continue this precedent-setting renewable integration. Together, we are making Hawaii an industry leader on many fronts.

As we make the transition to renewables, which in Hawaii can provide energy at a lower cost than our oil-based generation, our customers unfortunately continue to be burdened with the impact of high bills from high oil prices in the Asia-Pacific region. Thus, we have scrutinized expenditures and carefully reprioritized them to limit bill increases for our customers while still moving our state toward a clean energy future and delivering on our main franchise obligation to provide safe, affordable, reliable, and clean electricity for our customers.

Financially, our 2013 earnings were consistent with our expectations and guidance, and we were pleased to be able to deliver a consolidated ROE of 9.7% for investors.

As shown on slide 3, earnings of $1.62 per share in 2013 were down $0.06 from $1.68 per share on a core earnings basis, but consistent with our guidance. The decline from 2012 was due to slightly lower earnings at both operating companies and share dilution resulting from our equity investments into our electric utility. On a GAAP basis, 2013 EPS was higher because 2012 included a fourth-quarter charge.

As shown on slide 4, HEI consolidated 2013 ROE was 9.7% versus 10.4% in 2012, which reflects higher equity from our increasing investments into the utility. The utility's 2013 ROE was 8%, and the bank continued to provide a strong ROE of 11.4% while continuing to maintain a conservative risk profile.

Turning to slide 5, the utility along with many stakeholders in Hawaii's energy ecosystem continued to make significant progress in the state's clean energy goal to reduce Hawaii's dependence on oil as quickly as possible. Utility sales from renewable energy were 18% in 2013, which surpassed Hawaii's 2015 renewable portfolio standard of 15%.

We continue to lead the nation in the integration of customer-sited solar. Here on the most populated island of Oahu, 10% of our customers have rooftop solar while the next most active utilities in the United States are only at 2% to 3%. And in 2013, our use of renewable generation displaced the use of about 2.9 million barrels of oil which would have cost our customers approximately $350 million in imported oil.

Further advancing our RPF goals, just last week 30 megawatt wind IPP was brought back on our system at full capacity. Operations had previously been extended in August 2012 due to a fire in its battery. We are pleased that we were able to collaborate with the developer on an alternative technology to regulate will voltage swings.

This innovative technology allows the wind farm to come back online without a battery and at a lower cost to our customers.

As I mentioned earlier, a key long and short-term focus for us has been to explore every way possible to lower our customers' high oil-based bills. One of our initiatives has been to solicit renewable developers who can deliver power quickly and at prices significantly below our oil-based cost of generation. We have asked Hawaii Public Utilities Commission for approval to waive competitive bidding and allow us to negotiate with nine developers a proposed utility-scale solar facility on Oahu.

These projects totaled 244 megawatts of capacity at an average price of one quarter to one-third less than the current avoided cost of generating electricity from oil. By accelerating the process, we hope to preserve developer tax benefits that will expire in 2016, which can lower the price for our customers.

Just last week, we received commission approval of waivers for three of the nine projects totaling 33 megawatts, and we are beginning negotiations. The individual contracts will, of course, be subject to PUC approval.

In addition, our utility's own request for a low-cost 15 megawatt photovoltaic system on land at our Kahe Generating Station is pending review by the PUC along with the remaining six IPP waiver projects. As a result of the level of renewable integration we have been able to achieve, we have initiated plans to deactivate our older, less efficient oil-burning generating units in 2013. This helps lower oil consumption and electric bills for our customers and helps us increase the use of renewable energy.

In 2013, Hawaii Island shipment plant was deactivated. And just last month, Honolulu power plant began deactivation. Two units at the [Wai'a] power plant on Oahu are also scheduled for deactivation by 2016. And on Maui two of four generating units at the Kahului power plant are being deactivated, and we have plans to retire all four units by 2019.

While internal operating costs are less than 15% of the total billed to our customers, we are very focused on cost management to address that part of the bill, too. In 2013, we managed operating expenses to less than inflationary increases, and we've initiated a goal to continue to manage base O&M at inflationary levels for the next several years.

We also refinanced $166 million of debt in 2013 at lower rates. The weighted average interest rate of new debt was 4.6% compared to the debt replaced which was 5.4%. We've leveraged partnerships and have over $20 million in grant funding from federal, state, and industry sources to help us investigate, pilot, and gain insight to better inform clean energy solutions. And we've also reduced and reprioritized our CapEx plan to help limit increases on our customer bills while bills remain high.

Another potentially significant contributor to more affordable bills for customers is replacing the remaining oil we would otherwise use with liquefied natural gas, as Hawaii has no natural gas. We completed studies on the viability and benefits of LNG and are working with others to bring LNG to Hawaii on an accelerated basis for the benefit of our customers.

Turning to American Savings Bank on slide 7. For the year, our bank team exceeded all of its financial targets for return on assets, loan growth, net interest margin, and net charge-offs. The bank's priorities in 2013 focused on loan growth with a goal in the mid-single-digit range. The bank exceeded this goal with actual loan growth of 9.7% in its targeted segments of residential mortgages, home equity lending, commercial real estate, and commercial and industrial lending.

Although we expected loan growth to moderate in the fourth quarter as interest rates kicked up, it remained strong despite the drop in residential mortgage production, driven primarily by higher home equity lines of credit, commercial real estate, and commercial market loans.

We gained residential market share and improved our ranking to number three from number seven a couple of years ago and maintained our number one ranking in the state for the third year in a row in home equity line of credit loan production, growing the portfolio by 17% in 2013.

Our strong loan growth helped offset the impact of the decline in net interest margin. 2013 net interest margin was 3.74%, which was slightly above our target range of 3.6% to 3.7% for the year. As we grew, our priority is always to maintain strong asset quality and improved risk management. Our systems resulted in the 2013 net charge-off ratio of 9 basis points beating our target of 19 basis points and extremely low relative to our peers.

As a result, we maintained an attractive ROA of 113 basis points compared to our target of 110 basis points and peers at 98 basis points. Overall, the bank continues to maintain its low-risk profile, strong balance sheet, terrific funding base, and straightforward business model.

The bank's overall strategy is to focus on its core banking business, growing loans and deposits and generating fee income by providing an attractive value proposition for customers.

In 2014, the bank is targeting mid-single-digit loan growth in order to offset the continued impact of lower yields. The bank expects balance loan growth generally consistent with the current portfolio mix with somewhat faster growth in consumer and commercial real estate, but avoiding concentrations to high loss severity exposures and complex segments in order to maintain their strong asset quality.

The bank continues to focus on cost management in core operations as it funds critical initiatives for long-term growth. Overall costs will be lower in 2014 while still investing in data management and sales management tools to support more sophisticated analytics and risk management. Through the bank's effort, we expect to deliver above peer average return.

I'll now ask Jim to provide additional detail and insight to our results and our outlook for 2014.

Thanks, Connie. I'll start by briefly commenting on factors driving Hawaii's economy. Hawaii's tourism industry set a new record in 2013, and visitor arrivals were up 2.6% over 2012 to 8.2 million arrivals. Compared to 2012, visitor arrivals grew 2% -- expenditures grew 2% up to $14.5 billion in 2013.

Seasonally adjusted statewide unemployment is relatively stable at 4.5% with Honolulu at 3.8% in December 2013, lower than the state's 5.1% rate in December 2012 and the national unemployment rate of 6.7%.

Hawaii real estate activity, as indicated by the home resell market, was strong in 2013. The median sales price for single-family residential homes on Oahu increased 4.8%, and the number of closed sales increased 4.6% over 2012. Additionally, 2013 Hawaii residential building permits increased 22% over 2012.

Overall, we expect continuing growth in Hawaii's economy in 2014 supported by continued recovery in the construction industry and steady but slower growth in the visitor industry.

On slide 10, core utility earnings were $122.9 million in 2013 compared to $123.7 million in 2012. EPS of $1.23 was generally consistent with the high end of our guidance range of $1.18 to $1.22 in part due to strong expense management and in part due to less common stock issued by HEI than we had originally planned.

In 2013 on an after-tax basis, the most significant year-over-year net income drivers were $11 million higher recovery of additional infrastructure investments in operating costs, $4 million lower earnings from the final decision in the Maui 2012 case, and $2 million lower earnings from the fuel efficiency performance of our generating units.

Higher net revenues were more than offset by higher depreciation, lower AFUDC and higher O&M expense.

O&M expense was $2 million or 0.9% higher compared to last year and less than inflationary levels. Cost efficiencies in generation and T&D helped offset higher customer service costs which were expensed in advance of recovery. In 2013, utility earnings benefited from a nonrecurring $2 million deferred income tax adjustment versus 2012, which benefited from a $1 million tax settlement.

At the bank, net income for the year was $57.5 million, or EPS of $0.58, which is at the high end of our guidance range. The most significant drivers of the $1 million net income decline from 2012 were on an after-tax basis: $2 million of lower net interest income primarily driven by lower yields on loans, which more than offset the favorable contributions of loan growth and $7 million in lower provision expense; $2 million lower noninterest income primarily due to lower mortgage banking income and lower interchange fees as expected from the Durbin amendment which became effective for Americans on July 1; and, finally, $4 million in higher noninterest expense driven primarily by higher loan and investment product -- production volumes, sales- and performance-related incentives, and inflation-related increases in benefits.

Turning to the utility on slide 12 showed the utility's actual ROE's for the year ended December 2013. The consolidated to core ROE of 8% declined from 8.6% in December 2012, primarily due to additional equity to fund infrastructure investments.

Turning to slide 13, we wanted to provide an update on the will PUC's review of decoupling which was initiated last year. Earlier this month, we received PUC's decision and order on Schedule A issues, which resulted in two modifications to the decoupling model. First, carrying charge allowed on the revenue balancing account was reduced from 6% to the utility short-term borrowing rates in their last rate cases, rates ranging from 1.25% to 3.25%. The 2014 impact of this change largely depends on sales. We estimate the 2014 impact of this change to be about $2 million to $3 million after tax.

Second, the commission is very interested in continuing to evaluate the implementation of incentive mechanisms, particularly for cost management. As an interim measure, the PUC determined that the annual rate base RAM increase will be included in rates at 90% of the total amount. In 2014, the impact expected to be $1 million to $2 million in after-tax earnings.

Together we estimate these modifications will have a 20 basis points impact on our structural ROE GAAP, bringing it to 100 to 130 basis points.

Schedule B items, which encompass a broader range of issues including performance incentives, continue to be evaluated and are scheduled for hearings in August. Under the decoupling mechanism, we are required to file a rate case once every three years.

Slide 14 reflects the utility's updated three-year capital expenditure forecast of $1.1 billion. We have reprioritized CapEx to new targeted levels to help manage customer bills. We are targeting to keep CapEx in the range of $350 million to $400 million in the next few years. In addition, we will continue to work with the commission on several large initiatives, such as Smart Grid, and we will keep you informed of the progress of these projects. We no longer assume the same amount -- kind of utility-owned generation included in last year's CapEx plan except for the Kahe Solar and the unit at Schofield, a local military base for energy security and system optimization.

Our plans include replacing the fuel infrastructure project, originally budgeted at and undiscounted amount of $240 million, with a less costly LNG solution. We are seeking a series of LNG options that will balance timeliness and costs. Our current CapEx plan assumes the retrofitting of our generating units with minimal investments in [sure side] facilities.

Our ERP, ERM software for integrated business operations, originally budgeted at an undiscounted amount of $85 million in 2014 and 2015, has been delayed a year. Based on our revised CapEx plans we expect 2014 rate base growth of approximately 8% to 9%. Over the next three years, we estimate rate base growth of approximately 9%.

I'll now discuss the bank. On slide 16, our net interest margin of 3.67% in the fourth quarter 2013 was six basis points lower than the linked quarter. Total asset yield declined by 4 basis points largely attributed to lower yields on loans as loans continued to reprice down in this lower interest rate environment, although at a slower pace.

Our liability cost of 23 basis points in the fourth quarter of 2013 was 1 basis point higher than the linked quarter but still extremely low by industry comparisons. With interest rates rising and steepening yield curve, it will take some time for our assets to reprice higher than current portfolio rates. For most of 2014 we expect continued NIM compression as new pricing on loans continue to be lower than our portfolio rates, particularly in our mortgage portfolio.

Based our market expectations of rising interest rates, we anticipate that NIM will begin to recover by the end of the year.

On slide 17, we show the declining trend in noninterest income in 2013, which was primarily driven by lower mortgage banking income as the refinancing market contracted dramatically since mid-2013 and lower fees from other financial services related to the Durbin Amendment limits on interchange fees.

For the full-year, the $3.6 million pretax decline compared to 2012 was driven by $6.3 million in lower mortgage banking income, $3.3 million lower interchange fee driven by $4 million lower rates due to Durbin, but partially offset by higher volume. These declines were partially mitigated by $2.3 million gain on the sale of the credit portfolio, and $1 million in higher gain on sale of securities reflected in other income, and $1.8 million in higher fee income generated by American insurance and investments as we further developed this service with both new and existing customers.

In the fourth quarter of 2013, noninterest income was $3.2 million lower than in the linked quarter largely due to the third quarter $2.3 million gain on the sale of the credit card portfolio.

As a result of the healthy Hawaii economy and our enhanced risk-management efforts, we saw continued improvement in credit quality over the year. Provision for loan losses for the year of $1.5 million was in line with our revised 2013 guidance range of $1 million to $3 million and $11.4 million lower than 2012.

The unusually low provision in 2013 was a result of a combination of lower level of gross charge-offs totaling $8.2 million in 2013 compared to $12.8 million in 2012. Higher than normal level of recoveries of $4.8 million related to improvement in vacant land values and repurchases from our mainland residential portfolio, which had elevated recoveries in the last two years.

And then $1 million in release of reserves related to the sale of the credit card portfolio in 2013. 2013 net charge-offs were a low of 0.09% compared to 0.24% from the prior year. The allowance for loan losses was 0.97% of outstanding loans at $40.1 million at year end, slightly lower than the 1.01% compared to the linked quarter and 1.11% as of the prior year end.

On slide 19, American's nonperforming assets ratio of 1.2% was 13 basis points lower compared to the end of the third quarter and lower than the 1.87% at the end of the fourth quarter last year and remains better than its high performing peers. This is consistent with the overall improvement in credit quality, effective risk management, and the shrinking land and mainland residential loan portfolios.

Slide 20 illustrates American's continued attractive asset and funding mix relative to our peer banks. American's December 31, 2013, balance sheet is stacked against the last completed available data for our peers, which was September 2013. 96% of our loan portfolio was funded with low-cost core deposits versus the aggregate of our peers at 92%.

In 2013, core deposits increased by $189 million to $3.9 billion, which helped fund our strong loan growth while maintaining a very low cost of funds of 23 basis points in the fourth quarter 2013, 18 basis points lower than the median of our peers.

Other borrowings increased by $49 million reflecting the five-year FHLB borrowing agreements to support our loan growth. American remains well-capitalized with a leverage ratio of 9.1%, tangible common equity total assets of 8.5%, and total risk-based capital of 12.1% at December 31, 2013.

Management's analysis to date indicates that its current capital structure is more than adequate to satisfy the new capital rules for the Basel III framework, which become effective on January 1, 2015. In 2013, American paid $40 million in dividends to Hawaiian Electric Industries while maintaining solid capital levels.

Now, I'll address HEI's outlook for 2014. HEI is going into 2014 with a strong capital structure with 51% consolidated common equity to total capitalization at year end 2013. In December, we partially settled 1.3 million shares of our equity forward for $32 million in proceeds, less equity than we had originally planned and guided, primarily due to the lower 2013 CapEx of the utility. Proceeds were invested into the utility to maintain a strong capital structure.

On January 21, 2014, Fitch ratings assigned an investment grade rating to our companies. And over the last month, both Moody's and S&P confirmed our ratings. Our 2014 financing plans assume approximately $45 million of equity issuance through DRIP and/or the equity forward, and we expect to refinance $100 million of long-term debt at the holding company and to refinance the remainder of our needs via short-term debt.

Our dividend policy remains the same and will be reconsidered when earnings consistently support a 65% payout ratio.

Based on our current environment and expectations, we are initiating 2014 earnings guidance in the range of $1.57 to $1.67 per share. We expect utility earnings growth with a 2013 -- 2014 EPS range of $1.28 to $1.33 to be partially offset by lower bank EPS in the range of $0.47 to $0.52. Based on the revised CapEx plan and the 51% common equity capitalization target, we expect our 2014 to 2016 equity needs to be satisfied through DRIP and/or the existing equity forward.

At the utility, our guidance assumes the recent PUC decision on decoupling Schedule A issues, but does not project future regulatory decisions including the second set of issues to be addressed in the pending decoupling docket. We assumed cost management to keep O&M flat in 2013 while continuing to execute higher priority strategies.

Fuel efficiency consistent with rate case levels and related heat rate deadband; however, changes in the system demands could cause fuel efficiency to fluctuate outside the deadband. As stated earlier, rate-based growth in the 8% to 9% range. Overall, we expect 2014 utility ROE to range between 8% and 8.3%.

At the bank, mid-single-digit loan growth which we expect to more than offset the effect of lower NIM on net interest margin. We expect NIM to be between 3.6% and 3.7% as we expect new pricing on loans to continue to be lower than our portfolio rates for most of the year. The full impact of the Durbin Amendment on interchange fees, which is expected to reduce net income by $6 million or an additional $3 million over last year. Continued decline in mortgage banking income as mortgage production declines with the refinancing market compared to 2013.

In 2014, we expect gross charge-offs to remain low, but recoveries to return to more normalized levels. Thus, we expect provision to be in the range of $5 million to $7 million, slightly higher than 2013 when contemplating additional reserves for projected loan growth.

Overall, we expect return on assets of approximately 95 to 100 basis points with the effect of the interchange caps under the Durbin Amendment representing a reduction of approximately 11 basis points compared to when the bank was exempt from these caps.

Now, I will turn the call back to Connie for closing remarks.

Thanks, Jim. In summary, our utility is at the forefront of the industry in integrating renewable and distributed generation. Together with our regulators, policymakers, and other stakeholders we are making Hawaii a leader in clean energy. As we continue to transition to a clean energy future, our utility continues to be focused on affordable costs and excellent service for all of our customers. Our bank continues to be a solid performer and will continue to focus on its core banking business, targeting mid-single-digit loan growth, strong credit quality, and above average peer return.

Overall, HEI's unique business model continues to provide our Company with the financial resources to invest in the strategic growth of our Company while supporting the continued stability of our dividend, which we have paid for over 100 consecutive years. Last week, we announced that our Board maintained a quarterly dividend of $0.31 per share. Our dividend yield continues to be attractive at 4.7% as of Friday's close.

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

(Operator Instructions) Charles Fishman, MorningStar.

Thank you, I just want to make sure I understand on slide 14 as I look at the CapEx forecast, that is pretty much -- it looks very similar equivalent, if you will, to the maintenance CapEx on this graph that you used previously or your previous CapEx forecast. Is that -- I mean, basically, you've eliminated the major initiatives from the forecast. Is that correct?

Charles, this is Tayne. Let me comment on your question there. So what we did was we reprioritized the CapEx to something that's more targeted to help us address customer build. The maintenance CapEx for these years is roughly $250 million to $300 million, and that's through a re-prioritization process. As Jim mentioned in his remarks, we also are not assuming the same amount or kind of utility-owned generation and our plans now include the military-sited generation for energy security.

The other important point there for 2014 with our -- there's a delay in our ERP project, which basically moved out the CapEx for 2014 out a year.

Okay, so if I look at the -- previously you were talking $350 million for 2014 maintenance CapEx. That's actually now been reduced between the $250 million to $300 million?

That's correct.

But yet you still -- you're still talking an 8% to 9% rate base growth?

That's right.

And you're eliminating some of the old diesel plants, which I assume just had some very low basis. Is that why it really doesn't have much of an impact on your rate base growth?

That's correct.

And then my second question is you mentioned a wind farm that was part of a power purchase agreement. What island was that on?

That was on the island of Oahu.

Okay. Now, in shifting to Maui where last year you had some issues with respect to renewable utilization, is that pretty much in the rearview mirror that that's a nonissue going forward?

Well, we continue to work on it, and I think, as we've disclosed previously, we now are accessing up to 94% of the power from all of the wind farms that are on Maui.

Okay, so surely that -- I would think that would meet the commission's expectations at this point, correct?

We would hope so. But there are many people in Hawaii who want to add additional renewable generation, and so, that's the reason why we're continuing to work so hard with the industry here and the renewable developers and look at all kinds of technology that can allow us to integrate more renewables going forward.

Okay, thank --.

(multiple speakers) Hawaii to become a leader and we need to keep moving forward on that front.

Okay, thank you.

Paul Patterson, Glenrock Associates.

Just a follow-up on Charles's question. Sorry I didn't really understand the answer when you said it's a rate-based growth. It looks like a really major reduction in CapEx, yet rate basis growing. And I missed exactly why rate base is growing as much if you had such a big reduction in CapEx expenses.

This is Tayne. A large part of our CapEx reduction had been in the bigger projects so we do have the maintenance CapEx, the smaller type projects, which tend to close out quicker. So it's really a different mix of projects in the total CapEx planned.

So these other projects -- so I guess a portion of the CapEx wasn't really expected to be in rate base prior? Is that right and now it is? Is that how we should think about it? I mean, could you just clarify that?

Yes, so for example where we had some facilities projects that were expected to spend in 2014 and 2015, those are being delayed and moved out. And so, they really didn't have much impact on the rate-based growth because those projects have longer lead time to completing.

So, Paul, a lot of it has to do with the timing of completion of those multiyear projects.

Okay, but it does, I guess -- it would impact under the RAM though some of your -- I mean, how should we think about the financial impact of less CapEx both in terms of earnings and also in terms of the equity forward that you guys have out there?

So, Paul, it doesn't affect the really near-term years, but it does effect the longer-term out years. And so, one of other things that we will do, as we have in the past, is to manage the equity requirements to support the CapEx program, and that will include the use of the equity forward, which as you know gives us better flexibility with respect to timing on when we can draw down that forward. For example, as Jim commented, we drew less at the very end of the year. I think it was $32 million, Jim?

Correct.

Against the roughly 172 net proceeds that were available on that equity forward.

And you are expecting $45 million this year. Is that right?

That's right, Paul. Either through the DRIP or the forwarding combination.

And Paul, I would just add our DRIP now is bringing in about $48 million a year roughly.

Okay, and then with respect to the deferred tax issue that the commission ruled on and Schedule A, what was the impact of that?

There was no impact because it's something that needs to be further discussed in Schedule B.

Okay. What would be impact be if in fact that was -- if that wasn't around for 2014? Or how should we think about the potential financial impact of that?

Paul, it's Jim. The commission really ordered that the Company evaluate its accounting treatment for that and file with the service within 120 days. So, we are evaluating those options now. It's really too soon to be able to predict what the specific financial impact, if any, would be on this.

Okay, now, I realize running out of questions. So, just finally, the fact that there's been, again, we see this desire it appears voiced through to these orders for an increase level of risk or skin in the game or performance-based. Could that potentially change the CapEx? I mean, if there is a substantial change in RAM or more perception of the need for putting the Company more risk or what have you, could that potentially change the capital expenditures or should we assume -- is the capital expense that you guys are currently forecasting based on really no significant change in RAM so far? That's I guess what I'm sort of asking.

No, I think, as Tayne indicated, we have scrutinized our CapEx budget and have reflected that in the slide that is in this presentation. But as to your base question, the answer is no. It won't change our capital plans in the sense that we always need to look at what we need to spend in order to ensure that we can provide reliable, affordable clean electricity for our customers. And it's very important everyone here in Hawaii to continue to move towards clean energy. So, we are continuing to keep that in mind as we plan the capital expenditures going forward.

Okay, thanks so much.

[Joe Zoe, Avon Capital Advisors].

I just have a quick question on your equity needs. I see on slide 23 you guided the equity needs to expected to be satisfied with existing equity forward and/or DRIP. So given the lower CapEx you guided, do you need all the equity you issued in forward or you just need a partial of it?

Joe, this is Jim. Thank you for the question. So far for this year coming, 2014, we are providing guidance only to that extent. So we'll reevaluate next year again, but -- so what I'm prepared to tell you is that we need really about $45 million this year and will evaluate the right source at the right time for this particular need as we get closer to the end of the year. We have in the past episodically closed the DRIP for original issuance shares. So, we have quite a lot of flexibility here with respect to doing that. And as you may know from watching others who have done the forward, there are possibilities to extend the maturity date of the forward. I'm not predicting that right now, but I do say that we have flexibility in both programs to manage against the CapEx plan that the utility has going forward. But this guidance is really relating to 2014. And only 2014.

Okay, thank you.

Michael Goldenberg, Luminus Management.

I want to understand this forward history again -- the equity forward. So you sold 125 but you haven't issued all of them. Are you saying that you're only going to do DRIP this year of 45 and nothing in the equity forward? I just want to make sure that that is what you're saying.

Michael, this is Jim. Thank you. So, we have needs this year of estimated $45 million. We can satisfy those needs by drawing some from the equity forward and some from the DRIP, all from the equity forward or all from the DRIP. We have quite a bit of flexibility. So it's the amount that we want to leave you with is $45 million, and the way we satisfied that will be done in the most cost-effective way. (multiple speakers)

I would just add that the gross number was not $125 million, but it was $180 million.

Very good.

I'm sorry, I apologize. And you did $50 million out of the $180 million?

We did $32 million out of the $180 million. So far.

$32 million. So does the forward -- what is the expiration then of the forward? And what happens to the forward if it expires without being fully used? Is there any cost to the Company in that?

The maturity date of the forward is March of 2015, and then it could be net settled without settling on the shares on a cash basis. And of course, there is an expense to doing so, but we are preparing for longer-term capital expenditures. And we're actually quite pleased that we did the forward that we did last year. So, I expect to use the funds.

So if you don't use it and I assume if you don't use it through 2014 that leaves you with three months, what magnitude of cost are we talking about to not settle?

Well, there's a complicated calculation in the agreement, which I'd be glad to explain to you probably off-line, but you're always paying the dividend on these shares in any event. So that's one cost that you do have even though you don't have the accounting dilution before settling the shares.

Got you.

(Operator Instructions) Charles Fishman, MorningStar.

Thank you for the follow-up. Slide 13 on the decoupling review, RBA portion? And it was you're saying a $2 million to $3 million after-tax impact for 2014. What happened here is when the decoupling was put in place, the short-term interest rates were much higher, 6%. And this is just taking a look at them again and the impact of bringing those carrying costs down will impact to you to about $2 million to $3 million, because your borrowing costs are actually much lower than the 6%.

Yes, although the 6% was not chosen relative to short-term interest rates at the time, it was just a fixed rate that was chosen which was the rate that we pay on customer deposits.

Okay.

It just happened to be chosen. And the commission came back and said, really we should be looking at short-term borrowing rate, and let's go back and grab the rates from the last rate case.

Okay, so this is a part of core utility earnings, so the $2 million to $3 million after-tax impact or at least nine months of it is in your -- excuse me, I guess 10 months of it is in your guidance for 2014, correct?

Yes, that's correct. 10 months of it.

Okay, thank you.

David Paz, Wolfe Research.

Just had a question, what are your requested revenue adjustments under the decoupling mechanisms effective this June?

We have not yet filed for those. We'll be filing at the end of March.

Okay, but just for us, the way think about this, should we think since the 2014 CapEx is reduced by $140 million similar to the amount of CapEx in 2013 that it would be in the ballpark of the adjustments requested last June?

David, this is Tayne. I think that's the right way to think about it. If you look at our CapEx spending in 2013, we guided roughly the $350 million range. And if you look at our CapEx for 2014 at $360 million, it's pretty consistent there.

Okay great and then just a model question. What should we -- what do you use as like a depreciation forecast when you factor in your -- when you give the 9% rate-based growth?

Well, Tayne was saying, generally depreciation, of course, is by class of item, so I think we have depreciation schedule that has different depreciation lives for the different items.

And what you can also do is if you look at our stats supplement, you can see what our depreciation expense typically runs in the 3% to 4% range. So, you can look at historical information for guidance there.

Great, thank you.

Paul Patterson, Glenrock Associates.

Back to the deferred tax issue. My understanding is you guys don't expect it to actually impact 2014, but it may impact depending on what they decide to do 2015. Is that -- do I understand that right?

I am looking at Jim. I don't think that is quite the interpretation. What Jim was trying to explain earlier is that the deferred tax issue really is on the timing of the recognition of revenue or taxable income for tax purposes. And so, the taxes on that taxable income are going to be paid regardless of the timing. So, it's just a matter of timing of when those taxes are paid, and thus, the interest carry on those taxes for purposes of the RAM. So that's why Jim was indicating that first of all we have got to go in and work with the IRS to determine whether we can make that accounting change for tax purposes. And then it's really just that interest on the timing of the tax payments.

Okay. So can you give us any flavor as to what that potential impact would be, I guess? It doesn't sound that large. Am I understanding it correct or --?

I would say that it should not be material, and it is largely a timing-related matter.

Okay, good. And then -- I got you. So, then in terms of the efforts you guys are making in terms of keeping customer rates down and what have you, I was wondering -- the CapEx, like you mentioned, there's obviously some timing issues. There's some category issues. How should we think about what customer rates given those efforts and also your renewable -- the aggressive renewable restructuring and cost efforts you are making on that? How should we think about those benefiting customers? How much rates are going to be benefited by all of these aggressive actions you have been taking to keep rates under control? Can you quantify that at all? Do you follow what I'm saying?

The long-term impact is that what we've been trying to do -- and this hasn't changed -- is that there may be modest increases in our portion of the bill. But if we can continue to integrate renewables that have lower cost than our current cost of oil-based generation, then we can bring down the top part of the bill which relates to the fuel pass-through which is more than half of the bill. And that that should net net be a better trade-off for customers because net net that would result in bills being kept under control and possibly even decreasing.

And certainly if we can bring in something like LNG that could come in at 30% to 40% lower for that fuel portion, that would be a significant help as would those waiver projects that I talked about that have an average cost that is a quarter to a third less than our current oil-based generation. So we were very pleased that the commission has allowed us to proceed with the first three of the nine to negotiate EPAs.

Joe Zoe, Avon Capital Advisors.

I have a follow-on question on (inaudible) equity needs. I understand that you need $45 million of equity. Would you mind to elaborate that on the timing of issuance? I just want to know what share count should I assume for modeling purposes?

Actually, Joe, for that, as Jim indicated, the $45 million could be satisfied either through the dividend reinvestment program, which brings in about $48 million a year and would be sufficient and/or we could draw on the equity forward.

With respect to the equity forward, those shares actually have already been sold at the time that the forward was first put in place last year. And they would only increase share count when we actually draw down. Jim also indicated that with respect to the DRIP we have the flexibility, and we have periodically done what we call turn off the DRIP and stop the issuance of original issued shares. And so, we haven't yet made a decision as to how we're going to fund the current 2014 equity requirement, which we normally would do at year end, but we certainly have sufficient sources to fund it.

And Joe, I'm glad that you followed up because I want to emphasize something I said in the prepared remarks that I didn't quite clarify for Michael Goldenberg. Between the estimated proceeds for the DRIP and the existing equity forward, we should be able to satisfy all of our equity needs between 2014 and 2016 so, if you will, we are well-stocked during this period. And you probably recall that there is a 7 million share count associated with the equity forward. That doesn't tell you when to calculate those into your share count because I haven't told you whether I'm going to use the forward and/or the DRIP.

But you would know that $45 million at roughly the present share price would constitute about a 2% dilution per year, right? So a couple of points. About 2% dilution a year from the DRIP and that we'll be able to satisfy all of our equity needs for 2014, 2015 and 2016 by using those two sources. And we will just determine at the appropriate time at any time which of those two sources to use.

And Joe just to add in, the $32 million draw on the forward that we mentioned that we did this past December was equivalent to 1.3 million of the 7 million shares.

Okay, are you -- can you give me a share -- like average share count number for 2014? Is that possible to give me a range?

Yes, I do believe it is fair to assume about 103 million shares at the end of the 2014 frame, maybe a little less than that.

Okay and one more --

(multiple speakers) It should be about 2% to 2.5% dilution off the 100 million shares that we have outstanding today. So it's going to be in that 102 million to 103 million range -- Joe, does that help you?

Yes, if you don't mind last follow-up. Given this CapEx number, are you over -- is your equity ratio too high for this?

Not if you consider the three-year period that we are talking about, right? So you'll have $1.1 billion in CapEx, give or take, for this three-year period of time. Rate base will grow from about $2.5 billion or $2.6 billion to about $3.3 billion. You can roughly assume depreciation of about $150 million to $160 million a year. So, you can see that we'll need that much equity over that three-year period.

Okay, thank you very much.

Thank you. I'd like to turn the call back over to Ms. Shelee Kimura for closing comments.

Thank you for joining us today, everyone. Feel free to give me a call as always if you have any other questions. Thanks.

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