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Executives

Thomas R. Miller - Vice President and Treasurer

Bruce A. Williamson - Chief Executive Officer, President, Director and Member of Executive Committee

Darren J. Olagues - Chief Financial Officer and Senior Vice President of Finance

Keith D. Crump - Senior Vice President - Commercial Operations

Analysts

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Michael Klein - Sidoti & Company, LLC

Timothy Yee - KeyBanc Capital Markets Inc., Research Division

Cleco (CNL) Q4 2012 Earnings Call February 20, 2013 8:30 AM ET

Operator

Welcome to the Cleco Corporation Fourth Quarter 2012 Earnings Call. My name is John, and I'll be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Mr. Tom Miller. Mr. Miller, you may begin.

Thomas R. Miller

Good morning, and welcome to Cleco Corporation's Fourth Quarter and Year End 2012 Conference Call. You can access this call and slide presentations live via the Internet on Cleco's website, www.cleco.com/investors. Telephone and Internet replays can be accessed through our website. The dial-in number for the telephone replay is (888) 843-7419 or from outside the U.S., 6-306-523-042. The conference ID is 34069800.

With me on the call today are Bruce Williamson, President and Chief Executive Officer of Cleco; and Darren Olagues, Senior Vice President and Chief Financial Officer; along with other members of Cleco management.

Before we begin, please keep in mind that during the conference call, we will make some forward-looking statements. These statements are subject to many risks and uncertainties. Actual results may differ materially from those contemplated on our forward-looking statements. Please refer to our cautionary note regarding forward-looking statements and risk factors in various reports filed with the U.S. SEC, including our recently filed 2012 annual report on Form 10-K. In addition, please note that the date of this conference call is February 20, 2013, and any forward-looking statements that we make today are based on assumptions as of that date. With that, I'll turn it over to Bruce.

Bruce A. Williamson

Thank you, Tom. Good morning, and thank you for joining us. Let's start with the agenda for today's call, which is on Slide 3 of our presentation for those of you following along via the webcast. I'll begin with a recap of our major accomplishments in 2012, including a short review of earnings. Darren will then rediscuss our 2012 fourth quarter and year-end financial results and detail our earnings guidance in 2013 and planned capital expenditures for 2013 and beyond. After the financial review, I'll summarize some key points for you to consider regarding our strategic outlook for the future, then we'll take your questions.

Please turn with me to Slide 4, where we will now review our accomplishments for the past year. Despite somewhat -- starting with earnings, despite somewhat milder than normal and much milder than the 2 previous years' weather, Cleco had another strong year, with operational earnings of $2.46 per diluted share. These 2012 earnings results put us right at the top of our revised guidance range. These results were largely met due to our ability to drive down elements of our cost structure to set the legacy tax issues and in doing so, offset the impact of mild weather in 2012. Importantly, we're able to do this without impacting operations, reliability or customer service. Our attention to the operation of our utility and the success we realized with the new regulated wholesale contract support our efforts to grow our company and produce solid results for our shareholders.

Turning to dividends. After many years of focusing our -- on investment and our utility business since 2011, we have struck a more balanced approach to capital allocation and have increased our dividends to shareholders. Over the last 3 years, we've increased our dividend 4x for a total increase of 50%.

Our dividend yield for 2012 was 3.4%, with the dividend payout ratio of 55% within the midpoint of our targeted range of 50% to 60%. Going forward, we'll continue to evaluate our dividend quarterly.

In 2012, we made great strides in delivering a growth strategy. We had a strong start to the year by negotiating the largest wholesale power contract in our company's history. The Dixie Electric Membership Corporation or DEMCO contract was a big step towards helping us fulfill our growth strategy through regulated wholesale contracts. When the DEMCO contract begins in April 2014, our company will see load growth of approximately 20%. DEMCO serviced the fast growing Baton Rouge suburban market, which is close to our Northshore retail market. Together, this region has the potential to grow Cleco's earnings further over the life of the 10-year contract. DEMCO received approval for the contract from the Louisiana Public Service Commission or LPSC in October of 2012. To support the DEMCO contract, our regulated utility load requirements and add fuel cost flexibility for all of our customers' benefit, Cleco Power issued a 2012 long-term RFP in May for up to 800 megawatts.

In October, we announced that the Coughlin Power Station was the winning bidder. This selection is still subject to regulatory approval by both the LPSC and the Federal Energy Regulatory Commission. Cleco Power plans to make the necessary filings late in the first quarter or early second quarter to obtain these approvals. Coughlin is the only remaining asset in Midstream and when complete, the transfer of Coughlin to Cleco Power will end our unregulated business. With Coughlin, Cleco Power now has ample power supply to support DEMCO's load to pursue some additional wholesale load and the utility will add an efficient gas-fired units -- gas-fired unit to its fleet for the benefit of all of our customers.

Turning to Madison Unit 3 bonus depreciation. Last quarter, I told you that Cleco filed a private letter ruling request with the IRS to obtain a 50% bonus depreciation deduction on our Madison Unit 3 investment. On December 28, Cleco received a favorable ruling affirming the position taken on our 2011 Federal Income Tax Return. The $411 million depreciation deduction increases our net operating loss for 2011 to $478 million. Cleco plans to fully utilize this loss in future taxable income within the statutory period. We had to anticipate that the extension of bonus depreciation provided by the Taxpayer Relief Act of 2012 will also add approximately $80 million additional income tax deductions in 2013. When we put all this together, we do not expect to pay income taxes until 2015.

In 2012, we also completed our large transmission infrastructure upgrade in South Louisiana, the Acadiana Load Pocket or ALP project. Cleco Power added 68 miles of transmission lines, upgraded and built substations and made other improvements to this system. Cleco Power and 2 other utilities collaborated to develop a solution to power constraints in the area. Recently, FERC's office at the energy market regulation side of the project is a model for the rest of the nation's utilities on how to work together to solve transmission issues for the benefit of customers. Project costs came in slightly below the $125 million budget. Cleco Power is recovering the retail jurisdictional portion of this project through its formula rate plan.

Turning now to our transmission rate case. In 2012, in connection with the Acadiana Load Pocket project, we filed our first transmission rate case in over 20 years. The new rates allow recovery of Cleco Power's FERC-jurisdictional investments in transmission and other assets placed in service since the existing rates were established. On December 21, Cleco Power signed and filed a settlement agreement, which allows for an equity return of 10.5%, with an equity ratio of 53%. Cleco Power will discount the charges produced by this formula rate plan by 10% until the earlier of December 31, 2014 or the date when Cleco Power enters the Midwest Independent System Operator or MISO market. FERC approved the settlement for us a couple of weeks ago. Based on historical usage by wholesale users of our transmission system, we expect to increase base revenues by approximately $9 million annually.

Turning to MISO. We filed for a change of control request with the LPSC, seeking permission to join MISO in December of 2012. We feel MISO's market will bring efficiencies that will benefit our customers and our company because of MISO's stricter resource adequacy enforcement. This enforcement will likely tighten supply in the area as older, inefficient plants in the market that do not currently run could get de-rated and eventually removed as available capacity. Operating in the MISO market offers the opportunity to secure wholesale bids with our diverse generation fleet and make additional transmission investments. At this point, we plan to join MISO by January of next year.

So in summary, we had a very productive year in 2012 and look forward to completing these projects that will define our growth for the future. I'll now turn the call over to Darren to discuss fourth quarter and year-end results, capital expenditures and earnings guidance for 2013.

Darren J. Olagues

Thanks, Bruce, and good morning, everyone. Before reviewing the major drivers of our year-end performance, please turn to Slide 7 to discuss our fourth quarter results. Operational earnings for the quarter were down $0.09 to $0.36 a share compared to the fourth quarter of 2011. This excludes nonoperational items associated with life insurance policies and the expiring Acadia Unit 2 indemnification. GAAP earnings were $0.38 per diluted share for the fourth quarter of 2012, which is down $0.13 compared to fourth quarter 2011.

Now looking from left to right on the earnings reconciliation chart, Cleco Power's nonfuel-based revenue, net of customer refunds, was up $0.08 from last year. The effect of the formula rate plan adjustments that took effect July 1, 2012 increased earnings by $0.05 for the quarter. Earnings increased $0.02 due to lower customer rate refund accruals. Retail sales were up slightly versus 2011 and contributed an additional $0.01 per share. Other revenue was lower by $0.01. Other expenses decreased earnings by $0.04 as we had $0.03 of higher depreciation associated with the Acadiana Load Pocket transmission project, other additions to fixed assets and amortization expense and $0.01 of net unrecovered Coughlin capacity payments. Interest expense was lower and increased earnings by $0.03 a share in 2012, primarily due to lower interest on uncertain tax positions. AFUDC increased earnings by $0.02, mainly due to the advanced metering infrastructure initiative and miscellaneous transmission projects. Income taxes were higher and decreased earnings by $0.02 a share as the result of the loss of benefits related to state tax credits and other state tax attributes. And as you recall in the fourth quarter of 2011, we favorably settled our remaining tax issues with the IRS for the 2001, 2003 -- to 2003 tax years and recorded a net $0.15 earnings benefit. In 2012, earnings decreased by $0.15 due to the absence of the settlement effect.

Now moving to Slide 8, I'll recap the highlights for the year. Operational earnings were down $0.05 compared to 2011. Again, this excludes nonoperational items associated with life insurance policies, expiring Acadia Units 1 and 2 indemnifications and the 2011 gain related to the Acadia Unit 2 transaction.

Cleco Power's nonfuel-based revenue, net of customer refunds, increased earnings by $0.08 from last year. The effect of FRP adjustment that took effect in July 2011 and July 2012 and that primarily relate to ALP, Acadia and purchased capacity, including -- from the Coughlin toll increased earnings by $0.11. In addition, earnings increased $0.06 from lower customer rate refund accruals than what was recorded in 2011. For the year, retail sales at Cleco Power were down 3%, largely due to milder first quarter weather and contributed to an earnings decrease of $0.09. Other revenue at Cleco Power decreased earnings by $0.10, with $0.06 tied to lower mineral lease payments in 2012 and $0.05 due to the absence of a gain on fuel oil sales. Partially offsetting these reductions was $0.01 of higher miscellaneous revenue. Other expenses decreased earnings by $0.12 compared to 2011 due to $0.10 of higher depreciation and amortization expenses, resulting primarily from increased regulatory asset amortization and capital additions on the ALP project, generation-related capacity additions and other miscellaneous transmission projects. $0.07 was due to capacity tolling payments made under the Coughlin toll that were not recoverable from retail customers. Also contributing to the decrease was $0.02 of higher property taxes. These expenses were partially offset by $0.07 of other income and lower across-the-board operating expenses, which is reflective of our cost management efforts. Interest expense was down significantly and increased earnings by $0.20 per share, $0.05 relates to favorable treatment of deposits held on account with the IRS and $0.09 from lower interest on uncertain tax positions as we've trued up and reduced our corresponding reserves. The remaining $0.06 is due to lower consolidated borrowing costs and lower debt levels. AFUDC increased earnings by $0.03 related to the AMI project and miscellaneous transmission projects. Income taxes increased earnings by $0.01 compared to last year primarily due to an increase in tax credits, partially offset by adjustments related to filed tax returns. For the year, our consolidated effective tax rate was 28.5%. Finally, as noted earlier, earnings decreased in 2012 by $0.15 per share as a result of the absence of the 2001 to 2003 IRS settlement.

Now I'll move on to our 2013 earnings guidance on Slide 9. As you recall, our 2013 consolidated operational earnings guidance is $2.45 to $2.55 per diluted share, and we affirmed that in our earnings release yesterday. As a reminder, this guidance is based on normal weather conditions, minimal operational earnings contribution from Midstream and no impacts from adjustments related to life insurance policies and expiring Acadia Units 1 and 2 indemnification. This estimate also assumes the consolidated effective tax rate of 32%. When compared to our original 2012 guidance of $2.34 to $2.44 per diluted share, also based on normal weather, our 2013 guidance is approximately 5% higher. We expect to drive the increased earnings through revenue additions resulting from the transmission rate case, rate base growth and associated formula rate plan adjustments and increased recovery of Coughlin capacity tolling payments. Sustainable cost management of controllable expenses and lower interest expense will also drive increased earnings. Offsetting some of these benefits are higher generation outage costs and higher tax expense.

I'll now turn to Slide 10 to discuss our capital expenditure plan for 2013, as well as the 2013 to 2017 planning period. Note that the schedule reflects some minor updates from amounts discussed in earlier quarters. In addition to maintaining an average routine capital spend of approximately $110 million to $120 million per year over the next 5 years, our plan includes $17 million of capital in 2013 to complete our advanced metering infrastructure project. The plan also highlights the remaining capital needed to help us be MATS-compliant by 2014, 1 year earlier than required. And most of the MATS capital will be spent in 2013. Consistent with our current rate plan, we expect to finance the capital additions to rate base with 49% debt and 51% equity, and we are in a solid position to self-fund our equity capital needs. Looking beyond 2013, when capital needs beyond routine capital decline significantly, we expect to generate after-tax cash of $70 million to $100 million a year, including capital and dividends. With that, I'll turn the call back over to Bruce.

Bruce A. Williamson

Thanks, Darren. Before going into Q&A, I want to quickly review our outlook going forward, then our management team will join me in answering your questions. Please turn to Slide 12. In 2013, we plan to deliver on the projects we started in 2012. This year, we'll focus on the following key strategic issues. First, work closely with the LPSC to complete the transfer of Coughlin into Cleco Power as early as the fourth quarter and address several other regulatory filings to bring greater certainty to our customers and our shareholders. In addition, we plan to successfully transition the company into the MISO market. As an efficient natural gas-fired unit, Coughlin will add depth to our current regulated-generation fleet. Together with our proactive environmental upgrades to meet the U.S. EPA's MATS requirements, Coughlin will enhance the fleet's environmental performance as we face possible new environmental regulations. In addition, we expect our fleet to perform well in the MISO market as we continue to manage our operations and look for ways to maximize our units' availability. Joining MISO, we believe, will create opportunity through its expanded capacity and energy markets and enforcement of capacity requirements. With the transfer of Coughlin into the utility, we will transition to a single regulated business while focusing on expanding Cleco Power through regulated wholesale contracts to complement our retail territory load growth. And we have the financial support, as Darren said, to self-fund our growth strategy. We ended 2012 with liquidity of $556 million and a very strong balance sheet. When Coughlin moves to Cleco Power, we'll maintain the 51% equity, 49% debt-regulated capital structure. Cash realization, therefore, should grow in the future from the leveraging of Coughlin, the increase as a result of serving the DEMCO contract, and finally from the drop-off of our CapEx as we wind down our environmentally related CapEx program in 2013.

We've not also lost -- we also have not lost sight of our commitment to our shareholders. Our attention to sustainable cost management and growth options through wholesale opportunities are delivering solid returns for the -- for our shareholders. We've increased our dividend by 50% since May 2010, and we have based the midpoint of our 2013 guidance, we currently have a 54% payout ratio. We actively monitor opportunities to increase our dividend on a regular basis. Our total shareholder return for 2012 is 8%, and for 5 years, is 71%. We are committed to delivering you, our shareholders, solid growth within our regulated framework. These drivers bring value to our customers and shareholders alike and give us a positive growth outlook for the future. With that, we'll open the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Brian Russo from Ladenburg.

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Any update on the city of Alexandria RFP or any other defined contract opportunities that you see at this point?

Bruce A. Williamson

Brian, I know that the party you mentioned has had some commentary in regional newspapers. I think we would prefer to just say we're not going to comment on wholesale growth opportunities until we are ready to announce them.

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Okay, understood. And just to -- any thoughts on the strategy around the formula rate plan expiration next year?

Bruce A. Williamson

Well, as we've talked, I think, in some investor meetings and as I alluded to in my comments, I mean, I think what we would plan to do in 2013, given that we would be going to the Commission and addressing moving Coughlin in the MATS capital, we're bringing the bonus depreciation item, we're bringing enough items to the sort of to the table in 2013. It probably just makes sense to go ahead and address with the staff and the Commission, the likelihood of just trying to go ahead and address 2014 rates from 2014 on forward and just try to deal with that all in 2013. I think that will give both our customers and our shareholders a greater certainty. In effect, we have enough items coming on the table. We might as well go ahead and address everything all at once. I mean, Keith Crump is here, who heads our Regulatory and Commercial Group. I mean, Keith, anything you want to add to that?

Keith D. Crump

No. We have [indiscernible] approvals on where we need to be for '13. It's a lot of items at one time that we think are actually going to play positive for the customer's benefits also.

Bruce A. Williamson

Okay?

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Okay. And just curious, could you quantify the dollar amount of the cost cuts that were initiated in 2012?

Keith D. Crump

Well, I mean, actually, some of the cost cuts were initiated going back to 2011. This is where -- I know you want to get to sort of an annualized run rate, but -- so, yes. Some of the cost cuts early, Brian, were initiated in '11, and then some were initiated throughout 2012. And so if you just isolated those costs on a run-rate basis, I'll say that's probably somewhere in the $7 million to $10 million a year range. But I think we've talked about in the past, that's a very narrow way to look at and project out to '13 and '14 and beyond because there are other expenses that are rising. So it's not just a direct line to year-over-year earnings accretion. So part of it is hedging expenses and other expenses that are arising.

Bruce A. Williamson

I mean, Brian, I guess I would answer it a little bit like this. It probably applies to just about every utility in the country, when I was up in a conference, I don't know, about 3 or 4 weeks ago, I described utilities around the country is basically, we have a revenue or a top line that grows at around the 1% or so level, and we have expenses that left to their -- left by themselves are probably growing at 2% or 3%. And so if your revenue is going up 1% and your expenses are going up 3%, ultimately, that's not the sort of business model that shareholders are looking for us to produce. So what we're working on with our cost efforts around here is really to -- I would put it 2 ways. First off, the first part of your question that dealt with wholesale load growth, that's doing what we can to try to drive up our top line or our revenue function, if you will. And then by keeping kind of my thumb down -- or Darren and our thumbs down on expenses, we're basically trying to keep the expense -- expenses that are controllable down because there are other expenses that are noncontrollable that will continue to move up. So basically, I think, that utility management is trying to grow the revenue line and grow that function as much as we can and keep the expense function down as much as we can. And I think this year, we were very successful in that, particularly in the year, where due to weather year-over-year comparisons, we were actually down year-over-year.

Brian J. Russo - Ladenburg Thalmann & Co. Inc., Research Division

Okay, great. And then just lastly, you mentioned some, I believe, the outage costs in 2013. What quarter should we expect that in?

Darren J. Olagues

Brian, that would be tough for us to give out. But I guess, the main thrust of that comment was there are costs year-over-year, some costs that we've cut are sustainable. There are other things, outages, which are driven by timing and the use of the plant, and that is what dictates that. It would be tough to give us -- give you an actual target on the call.

Operator

Our next question comes from Michael Lapides from Goldman Sachs.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Just trying to think about the revenue bridge from 2012 to 2013. Can you just walk us through, the K gave some of the detail, the various revenue increases or revenue changes outside of demand changes that you expect in 2013 from 2012? Kind of what's embedded in guidance.

Bruce A. Williamson

I'll let Darren do that one.

Darren J. Olagues

Okay. Let's start with the transmission rate case sort of the FERC, the wholesale component. We've talked about that, that's on an annualized basis, $9 million year-over-year. I will say that we instituted rates right at the end. I think it was in November of 2011, so that's not 100% year-over-year, $9 million. But I guess, that also dovetails with the ALP on the state jurisdictional component, right, that we'll have. With that finished, we will start to see the full year impacts through the FRP adjustments of the ALP investment. I guess, just pause there and say, bear in mind that those are top line revenue adjustments that are happening. Obviously, as those things go into service, that we're depreciating those out. So there is a book depreciation impact, I'll call it offset from -- on a bottom line standpoint. The other item, in addition to those, would be the step-up in the Coughlin recovery, right? I think as you recall, right, our current deal started in May of 2012, and the recovery of that was at 480. The revenue stream was at 480, not the full 730 that the toll is actually under. That steps up from 480 to 730 in May of 2013, so we will see the full year impact of that. And I guess suffice it to say, in the first quarter of 2012, we had a very short term, I'll call it, very low-priced agreement between Coughlin and the utility for only 250 megawatts. That will be -- that will produce some revenue enhancement year-over-year. So all in all, there's a pretty significant increase, I think, in -- I won't give you the math because then you can reverse, engineer the pricing, which was not disclosed. But that is a significant uplift in the contribution coming from Coughlin. So those are sort of the revenue sides. And on the expense side, on a -- from a positive standpoint, we expect to see lower interest expense in part because of the full year effect of clearing out all these tax issues and lower tax on uncertain tax positions and then the cost, the net cost-cutting effect that we were just talking to Brian about.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. Hey, Darren, just a real quick follow-up. The ALP and the FRP, lot of acronyms there. Can you just talk -- can you quantify it since those are kind of in the public domain, what the revenue increases and the timing of when they go into effect, '12 to '13 bridge, please?

Darren J. Olagues

Yes. We have, I think in rates, the total spend on the project is right about $124 million. We have, in rates, through July 2012 so the full inclusion of the revenue impact in FRP adjustments, our annual formula rate plan adjustments, was $113 million. So when we look at, I think, the annual effect of FRP revenue from ALP, it's between $5 million and $6 million.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Meaning, in '13 from '12?

Darren J. Olagues

Well, that's the annualized piece. So there's -- you have to do a little bit of proration for the years. But sort of the long-term effect of ALP contribution on FRP is between $5 million and $6 million a year.

Bruce A. Williamson

In effect, some came in, in 2012. That's what you're saying.

Darren J. Olagues

Some have come in -- as the basis have come in, that's why it's tough to just give you what's the incremental step up because there's lots of pieces going into it, but it did. Some came in, in '12, some came in, in '11, some came in, in '12 and the remainder will come in, in '13.

Michael J. Lapides - Goldman Sachs Group Inc., Research Division

Got it. So the transmission case, some large percentage of the $9 million, the FRP-related to Acadiana, the ALP project, a couple million dollars year-over-year bridge, the Coughlin recovery, just trying to think about it, is that basically it?

Darren J. Olagues

Those are the primary drivers.

Operator

Our next question comes from Michael Klein from Sidoti & Company.

Michael Klein - Sidoti & Company, LLC

So with the opportunity to join MISO in 2014, I'm just trying to think about when you'll actually start or can potentially start to see some of that benefit. So if you join in 2014, when's the earliest that we can reasonably expect to see maybe some new wholesale load or some new contracts there? Would it not be until, maybe, 2016, 2017 once transmission starts to get synced up? Or can we start to see something in 2014?

Bruce A. Williamson

There's kind of 2 questions in there. One is, when do we think, hopefully, we'll see some new wholesale contracts. I mean, I would -- well, what we've done there, Michael, is to point people to kind of a time cycle around the DEMCO contract. Keith and his team, you may recall, completed the DEMCO contract on January 31, 2012. We announced it for -- in April of '14 start. So 26 months ahead of the start date. So they're out working now on contract opportunities that largely are starting more around the 2015 type of the timeline because of the lead time that a lot of these munis and co-ops would have, that seems to be about the right lead time, is about 2 years out. So I think that's one element of answering your question. The other part is, once we join MISO, when do we think we'll start to see an impact of kind of resource adequacy and the impact on capacity in the area because that could be a driver for some additional wholesale opportunities. I would tell you that I think what will probably happen is, together with the other utility, we join MISO in January of '14. 2014 then probably becomes a year of transition as MISO begins its enforcement process, calls on plans out of merit order, does this testing of capacity in the region. And that probably takes place, I would say, pretty much through 2014. It's not like we all wake up on January 1, '14 and suddenly, MISO decides to decertify plans and things like that. It'll be a year of transition as plans are called on and tested, and some will respond and some probably will not. And I think then the market probably then starts to change for capacity in 2015 and beyond. I'm looking down and I'm seeing Keith Crump nodding his head here. So I'm assuming, Keith, you agree in that general timeline?

Keith D. Crump

Yes. I think it'll take a good year to kind of get everybody used to the new rules. Okay?

Bruce A. Williamson

So Michael, does that answer your question?

Michael Klein - Sidoti & Company, LLC

It does. And lastly, can you just refresh us on the timeline remaining on the regulatory side with DEMCO between now and April, what still needs to get done and the timing of that?

Bruce A. Williamson

Sure, I'll kind of hit the highlights. I mean, DEMCO has gotten the approvals, so the contract is approved. On our side, in effect, we ran an RFP to acquire capacity sufficient to serve that contract because an affiliate was involved. In effect, that entire RFP process was run by an independent monitor with outside oversight by the LPSC staff. They made their selection of the Coughlin unit. Now it still has to go through and get official LPSC approval. But considering their staff and consultants and whatnot ran the process, I don't anticipate an issue there. And then it needs FERC approval. But to my knowledge, I don't think that's ever really traditionally been an issue. Because as I think of what the process is, what FERC is really largely doing is sort of passing the baton for regulation of the plant from the FERC level to the state level. So we plan on -- we're assuming that we basically follow very much the Acadia process and timeline. Those filings will go in, as I covered in my remarks, either very late in the first quarter or early in the second quarter. Anticipate that we will then have processes with both the LPSC and with FERC throughout pretty much the rest of 2013, so that we've got closure on that by maybe end of this year at the earliest, or very early of 2014 so that it's all resolved in time to start serving DEMCO in April of '14.

Operator

Our next question comes from Timothy Yee from KeyBanc.

Timothy Yee - KeyBanc Capital Markets Inc., Research Division

Could you just talk about your retail load growth assumptions for this year?

Bruce A. Williamson

Sure. Darren?

Darren J. Olagues

Yes. We are still projecting a base retail load growth of about 0.8%. But in fact, when you look back at load growth from '07, '12 in total, we've actually had a total load growth of 1.6% over the last 5 years, and the differential largely coming from commercial and industrial load additions, net much, of which came out of the Haynesville Shale, the Pine Prairie's storage facility load that we've talked about in past quarters. When we look out in 2013 and how much additional commercial load may come on to sort of further enhance that 0.8%, we do have some. There is -- it's delineated in the K, but we do have some that takes up our, I think, our 0.8% closer to 1% or slightly over 1%. So that we see as additional base revenue coming on throughout 2013. Michael, I didn't bring this up in your question. It's not that significant in '13 because they sort of stagger in, in '13. The dollars aren't that big, and then you start to see the full year effects in 2014 of these additions, these commercial load additions. So I think that the upshot, Tim, is that we think 0.8% is the long-term base retail load growth, with some supplement coming from commercial load still driven by gas drilling, and that takes us -- that would take us up closer to 1%.

Timothy Yee - KeyBanc Capital Markets Inc., Research Division

Okay. And you've talked, in your remarks, you talked about the completion after MATS, your free cash expectation, $70 million to $100 million annually. Could you just kind of remind us or refresh us, give us an update on what you're thinking potential uses of that cash?

Bruce A. Williamson

Sure. I mean, it basically comes down to, as I've talked with people, we get to 2014 and beyond. And when we start serving DEMCO and Coughlin is over in the utility and that sort of thing, in effect, you can look at like the slide on CapEx that they're uncovered. And while we have a run rate maintenance capital of around $110 million to $120 million a year, you can see our discretionary capital or rate base growth capital environmental as well as other initiatives, they basically tails off after this year. There's a little bit of environmental in '14 but not very much beyond that. And so we kind of have 2 functions that are going to take place starting in '14. Really, our operating cash flow will be moving up with serving DEMCO. Our investing cash flow requirements will be going down as environmental tails off and other growth capital tails off like AMI and ALP. And then that then drives up the free cash flow. So going forward, when we get to 2014 and beyond, we'll be looking at what are our options to deploy some capital into regulated, like growth options if we're successful on the wholesale -- on more wholesale contracting opportunities, then in effect, we're sort of shortening the cycle time for meeting new generation capacity. And if we can do that, we'd be looking at potentially buying or building some additional generating capacity out around if it's available probably starting in the 2017-or-so time period. And we'd have the ability to self-fund that if we're successful with that wholesale growth strategy. On the other hand, if we're not, then we'd be having to look at, ultimately, if we're not able to easily put up the people in investor meetings, we're not able to grow the left-hand side of our balance sheet, ultimately, we'll need to be looking at ways to shrink the right-hand side of the balance sheet. Now that has some attendant potential negative effects in terms of reducing our float and reducing our daily liquidity, things like that. So clearly, our drive as a company, like any good management team, is to try to deploy that cash and the regulated-like risk and regulated return in that 10, 7 type of horizon return on equity function. That's what we'll be driving towards. But ultimately, we'll see how our success is on the wholesale front. And in the meantime, throughout all that time period, Michael will be able to continue to work on our dividend pretty much all throughout this period. And I just would remind people, a $0.10 increase in our dividend is about $6 million of cash, so we've got plenty of liquidity to go ahead and continue to address our dividend going forward.

Operator

[Operator Instructions] We have no further questions at this time. Bruce, do you have any final remarks?

Bruce A. Williamson

Yes, thanks. I would just like to thank everybody for their interest in Cleco and for dialing in today. It was a very successful year. We'll be out on the road meeting with investors over sort of the next several months now as the -- now that the year is completed and look forward to seeing many of you then. Thanks very much.

Operator

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.

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