Hawaiian Electric Industries' CEO Discusses Q4 2013 Results - Earnings Call Transcript

Feb.18.14 | About: Hawaiian Electric (HE)

Hawaiian Electric Industries, Inc. (NYSE:HE)

Q4 2013 Earnings Conference Call

February 18, 2014 5:00 PM ET

Executives

Constance H. Lau - President and CEO; Chairman, Hawaiian Electric Company, Inc.; Chairman, American Savings Bank, F.S.B.

James A. Ajello – EVP and CFO

Tayne S. Y. Sekimura – SVP and CFO, Hawaiian Electric Company, Inc.

Shelee M.T. Kimura - Manager, IR and Strategic Planning

Analysts

Charles Fishman - Morningstar

Paul Patterson - Glenrock Associates

Michael Goldenberg - Luminus Management

David A. Paz - Wolfe Trahan

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2013 Hawaiian Electric Industries, Inc. Earnings Conference Call. My name is Celia, and I will be your operator for today. At this time, all participants are in a 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.

Shelee M.T. Kimura

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 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 materials, 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.

Constance H. 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 to 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 renewable 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 in setting renewable integration. Together, we are making Hawaii an industry leader on many fronts.

As we make the transition to renewable 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 towards 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's 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 RPS goals, just last week a 30 megawatt wind IPP was brought back on our system at full capacity. Operations had previously been suspended in August 2012 due to a fire in its battery. We are pleased that we were able to collaborate with a developer on an alternative technology to regulate voltage swings. This innovative technology allowed the windfarm 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 generation. We have asked the Hawaii Public Utilities Commission for approval to waive competitive bidding and allow us to negotiate with nine developers of proposed utility-scale solar facilities on Oahu.

These projects total 244 megawatts of capacity at an average price 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 Shipman plant was deactivated, and just last month Honolulu Power Plant began deactivation. Two units at the Waiau 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 bills 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 have 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 have leveraged partnership 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 have 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 ticked 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 loan. 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 to 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 balanced loan growth, generally consistent with the current portfolio mix with somewhat faster growth in consumer and commercial real estate, but avoiding concentration to high-logged 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 efforts, we expect to deliver above peer average returns.

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

James A. Ajello

Thanks Connie. I'll start by briefly commenting on factors driving Hawaii's economy. Hawaii's tourism industry set a new record in 2013 in visitor arrivals, were up 2.6% over 2012 to 8.2 million arrivals. Compared to 2012, visitor arrivals grew 2%, expenditures grew 2% to $14.5 billion in 2013. Seasonally adjusted state-wide 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's real estate activity, as indicated by the home resale 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 and operating costs, $4 million in lower earnings and 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 to 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 of lower provision expense, $2 million in lower noninterest income primarily due to lower mortgage banking income and lower interchange fees as expected from the Durbin Amendment which became effective for American on July 1, and finally $4 million in higher noninterest expense driven primarily by higher loan and investment production volumes, sales and performance related incentives and inflation related increases in benefits.

Turning to the Utility on Slide 12, shows the Utility's actual ROEs for the year ended December 2013. The consolidated 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 PUC's review of decoupling which was initiated last year. Earlier this month, we received the PUC's decision and order on Schedule A issues which resulted in two modifications to the decoupling model. First, the carrying charge allowed on the revenue balancing account was reduced from 6% to the Utility's short-term borrowing rates in their last rate cases, with 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 is impacted to be $1 million to $2 million in after-tax earnings. Together we estimate these modifications will have a 20 basis point impact on our structural ROE gap, 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'll continue to work with the commission on several large initiatives such as smart grid and we'll keep you informed of the progress of these projects. We no longer assume the same amount or 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 managing security and system optimization.

Our plans include replacing the field infrastructure project originally budgeted at an 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 shore-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 based growth of approximately 8% to 9%. Over the next three years, we estimate rate based 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 6 basis points lower than the linked-quarter. Total asset yield declined by 4 basis points, largely attributed to lower yields on loans as loans continue to re-price 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 re-price 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 rate, particularly in our mortgage portfolio. Based on our market expectation of rising interest rates, we anticipate that NIM will begin to recover by the end of the year.

On Slide 17, we show the accounting 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 pre-tax decline compared to 2012 was driven by $6.3 million in lower mortgage banking income, $3.3 million lower interchange fees, 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 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 develop this service for 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 credit card portfolio in 2013.

2013 net charge-offs were a low of 0.09% compared to 0.24% in 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 in 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 backed against the last completed available data for our peers, which is 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 with 23 basis points in the fourth quarter of 2013, 18 basis points lower than the median of our peers.

Other borrowings increased by $49 million reflecting the five-year FHLB borrowing agreements for our loan growth. American remains well-capitalized with a leverage ratio of 9.1%, tangible common equity assets of 8.5% and total risk-based capital 12.1% at December 31, 2013. Management analysis to-date indicates that its current capital structure is more than adequate to satisfy the new capital rules of 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 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 in long-term debt at the holding company and to refinance the remainder of our needs by a 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 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 assume cost management to keep O&M flat in 2013 while continuing to execute high 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 base 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 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'll turn the call back to Connie for closing remarks.

Constance H. Lau

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 the transition to a clean energy future, our Utility continues to be focused on affordable cost 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 the quarterly dividend of $0.31 per share. Our dividend yield continues to be attractive at 4.7% as of Friday close. And with that, we look forward to hearing your questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Charles Fishman, Morningstar. Please proceed.

Charles Fishman - Morningstar

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. Was that – I mean basically you have eliminated the major initiatives from your forecast, is that correct?

Tayne S. Y. Sekimura

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 bills. The maintenance CapEx for these years is roughly $250 million to $300 million, and that's through a reprioritization process. As Jim mentioned in his remarks, we also are not assuming the same amount or kind of Utility-owned generation and our plan now includes 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.

Charles Fishman - Morningstar

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

Tayne S. Y. Sekimura

That's correct.

Charles Fishman - Morningstar

Okay, but you're still talking an 8% to 9% rate base growth?

Tayne S. Y. Sekimura

That's right.

Charles Fishman - Morningstar

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

Tayne S. Y. Sekimura

That's correct.

Charles Fishman - Morningstar

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

Constance H. Lau

That was on the Island of Oahu.

Charles Fishman - Morningstar

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

Constance H. Lau

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

Charles Fishman - Morningstar

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

Constance H. Lau

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 are 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. [Indiscernible] and we need to keep moving forward on that front.

Charles Fishman - Morningstar

Okay, thank you.

Operator

Next question comes from the line of Paul Patterson, Glenrock Associates. Please proceed.

Paul Patterson - Glenrock Associates

Just to follow up on Charles' question, sorry, I didn't really understand the answer it’s a rate base growth. I mean looking at the really major reduction in CapEx, yet rate base is growing, and I missed exactly why rate base is growing as much if you had such a big reduction in CapEx.

Tayne S. Y. Sekimura

This is Tayne. A large part of our CapEx reduction has 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 plan.

Paul Patterson - Glenrock Associates

So these other projects, so I guess a portion of the proportion 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?

Tayne S. Y. Sekimura

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 base growth because those projects have sort of longer lead times to completing. So Paul, a lot of it has to do with the timing of completion of those multiyear projects.

Paul Patterson - Glenrock Associates

Okay, but it does I guess – but 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?

Tayne S. Y. Sekimura

So Paul, it doesn't affect the really near-term years but it does affect the longer-term out years, and so one of the other things that we'll do as we have in the past is to manage the equity requirements to support the CapEx programs 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?

James A. Ajello

Correct.

Tayne S. Y. Sekimura

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

Paul Patterson - Glenrock Associates

And you're expecting $45 million this year, is that right?

James A. Ajello

That's right, Paul, either through the DRIP or the forward in combination.

Constance H. Lau

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

Paul Patterson - Glenrock Associates

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

Tayne S. Y. Sekimura

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

Paul Patterson - Glenrock Associates

Okay, what would the impact be if in fact if that wasn't around for 2014 or how should we think about the potential financial impact of that?

James A. Ajello

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.

Paul Patterson - Glenrock Associates

Okay, now I've asked a lot of questions, so just finally, the fact that there's been again we see this desire [it appears] [ph] voice through these orders for an increased 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 at 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, what's the difference of that?

Constance H. Lau

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 stand in order to ensure that we can provide reliable, affordable, clean electricity for our customers and it's very important to 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.

Paul Patterson - Glenrock Associates

Okay, thanks so much.

Operator

The next question comes from the line of [Joe Zhou] [ph], Avon Capital Advisors. Please proceed.

Unidentified Analyst

Just have a quick question on your equity needs. I see on Slide 23, you guided equity needs 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?

James A. Ajello

Joe, this is Jim. So far for this year coming, 2014, we're providing guidance only to that extent. So we'll re-evaluate it next year again. So what I'm prepared to tell you is that we need really about $45 million this year and we'll 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 those programs to manage against the CapEx plan that the Utility has going forward, but this guidance is really relating to 2014 and only 2014.

Unidentified Analyst

Okay, thank you.

Operator

A question from the line of Michael Goldenberg, Luminus Management. Please proceed.

Michael Goldenberg - Luminus Management

I want to understand this forward issue again, the equity part, so you sold $125 million but you haven't issued all of them. Are you saying that you're only going to do DRIP this year of $45 million and then nothing in the equity forward, just want to make sure if that's what you're saying?

James A. Ajello

Michael, this is Jim. 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 of bit of flexibility. So it's the amount that we want to leave you with that's $45 million and the way we satisfy that will be done in the most cost-effective way.

Constance H. Lau

I'll probably add that the gross number was not $125 million, but it was $180 million.

Michael Goldenberg - Luminus Management

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

James A. Ajello

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

Michael Goldenberg - Luminus Management

$32 million. So just with forward, what is the expiration date of the forward and what happens to the forward if it expires without being fully used, if any cost to the Company in that?

James A. Ajello

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 are actually quite pleased that we did the forward that we did last year. So I expect to use the funds.

Michael Goldenberg - Luminus Management

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 [indiscernible]?

James A. Ajello

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 the 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.

Michael Goldenberg - Luminus Management

Got you.

Operator

(Operator Instructions) We do have a question from the line of Charles Fishman, Morningstar. Please proceed.

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. I mean 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 a little will impact you to about $2 million to $3 million because your borrowing costs were actually much lower than the 6%?

Tayne S. Y. Sekimura

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.

Charles Fishman - Morningstar

Okay.

Tayne S. Y. Sekimura

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

Charles Fishman - Morningstar

Okay, so this is 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, it is 10 months of it, is in your guidance for 2014, correct?

Tayne S. Y. Sekimura

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

Charles Fishman - Morningstar

Okay

Operator

A question from the line of David Paz, Wolfe Research. Please proceed.

David A. Paz - Wolfe Trahan

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

Constance H. Lau

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

David A. Paz - Wolfe Trahan

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

Tayne S. Y. Sekimura

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 to $350 million range and if you look at our CapEx for 2014 of $360 million, pretty consistent there.

David A. Paz - Wolfe Trahan

Okay, great. And then just a model question, what should we – what do you use as a depreciation forecast when you factor in –when you did the 9% rate base growth?

Constance H. Lau

As Tayne said, I mean generally depreciation of course is high class item. So I think we have depreciation schedule that has different depreciation lives for the different items.

Tayne S. Y. Sekimura

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

David A. Paz - Wolfe Trahan

Thank you.

Operator

We have a follow-up question from the line of Paul Patterson, Glenrock Associates. Please proceed.

Paul Patterson - Glenrock Associates

About the deferred tax issue, I mean my understand is, you guys don't expect it to actually impact 2014 but it may impact depending on what they decide to do in 2015, do I understand that right?

Constance H. Lau

I don't think that's 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 the timing of when those taxes are paid and thus the interest carry on those taxes for purposes of the RAM. And so that's why Jim was indicating that first of all we've 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 payment.

Paul Patterson - Glenrock Associates

Okay, so I mean can you give us any flavor as to what that potential impact would be, I guess? I mean it doesn't sound that large, am I understanding it correct?

James A. Ajello

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

Paul Patterson - Glenrock Associates

Okay, good. 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 obviously there's some timing issues, that are some category issues, how should we think about what customer rates given those efforts and also your renewable, the cost of renewable restructuring and cost efforts are making on that, how should we think about those benefiting customers, how much rates are going to be benefited by all these aggressive actions you've been taking to keep rates under control, can you qualify that at all, if you follow what I'm saying?

Constance H. Lau

Yes, the long-term impact is that what we've been trying to do and this haven'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 a 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 field 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 field 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 are very pleased that the commission has allowed us to proceed with the first three of the nine to negotiate PPA.

Operator

A follow-up and final question from the line of [Joe Zhou] [ph], Avon Capital Advisors. Please proceed.

Unidentified Analyst

I have a follow-on question on [indiscernible] equity needs, I understand that you need $45 million of equity, would you mind to elaborate that on the timing of issuance? I mean I just want to know what share count should I assume for [indiscernible]?

Constance H. Lau

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 issue shares. And so we haven't yet made a decision as to how we are going to fund the current 2014 equity requirements which we normally would do at year end, but we certainly have sufficient sources to fund it.

James A. Ajello

And Joe, I'm glad that you followed up because I want to emphasize something I said in the prepared remarks but 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'll go soft during this period. And you probably recall that there's 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 couple of points. About 2% dilution a year from the DRIP and that will be able to satisfy all of our equity needs for 2014, 2015 and 2016 by using those two sources and we'll just determine at the appropriate time, at any time, which of those two sources to use.

Constance H. Lau

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.

Unidentified Analyst

Okay, I mean can you give me a share – like average share count number for 2014, is it possible to give me a range?

James A. Ajello

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

Unidentified Analyst

Okay.

James A. Ajello

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

Unidentified Analyst

Yes, if you don't mind, the last follow-up, if you can give CapEx number, are you over – like your equity ratio like too high where it is?

James A. Ajello

Not if you consider the three-year period that we are talking about, right. So you'll have a $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.

Unidentified Analyst

Okay, thank you very much.

Operator

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

Shelee M.T. Kimura

Thank you for joining us today everyone. Feel free to give me a call after-hours if you have any other questions. Thanks.

Operator

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

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