Wisconsin Energy Management Discusses Q4 2013 Results - Earnings Call Transcript

| About: Wisconsin Energy (WEC)

Wisconsin Energy (NYSE:WEC)

Q4 2013 Earnings Call

February 06, 2014 2:00 pm ET

Executives

Gale E. Klappa - Chairman, Chief Executive Officer, Chairman of Executive Committee, Chief Executive Officer of Wisconsin Electric Power Company, Chief Executive Officer of Wisconsin Gas LLC, President of Wisconsin Electric Power Company, President of Wisconsin Gas LLC, Chairman of Wisconsin Electric Power Company, Chairman of Wisconsin Gas LLC

James Patrick Keyes - Chief Financial Officer and Executive Vice President

Stephen P. Dickson - Principal Accounting Officer, Vice President and Controller

Allen L. Leverett - President, Executive Vice President of Wisconsin Electric Power Company, Chief Executive Officer of We Generation Operations and President of We Generation Operations

Analysts

James D. von Riesemann - CRT Capital Group LLC, Research Division

Kit Konolige - BGC Partners, Inc., Research Division

Jonathan P. Arnold - Deutsche Bank AG, Research Division

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

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Nathan Judge - Atlantic Equities LLP

Dan Jenkins

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

Andrew Bischof - Morningstar Inc., Research Division

Vedula Murti

Leon Dubov

Michael Weinstein

Operator

Good afternoon, ladies and gentlemen. Thank you for waiting, and welcome to Wisconsin Energy's Conference Call to Review 2013 Year End Results. This conference call is being recorded for rebroadcast. [Operator Instructions]

Before the conference call begins, I will read the forward-looking language. All statements in this presentation other than historical facts are forward-looking statements that involve risks and uncertainties which are subject to change at any time. Such statements are based on management's expectations at the time they are made. In addition to the assumptions and other factors referred to in connection with the statements, factors described in the company's latest Form 10-K and subsequent reports filed with the Securities and Exchange Commission could cause actual results to differ materially from those contemplated. During the discussion, referenced earnings per share will be based on diluted earnings per share unless otherwise noted. After the presentation, the conference will be open to analysts for questions and answers.

In conjunction with this call, Wisconsin Energy has posted a package of detailed financial information on its website at www.wisconsinenergy.com. A replay of our remarks will be available approximately 2 hours after the conclusion of this call.

And now it's my pleasure to introduce Mr. Gale Klappa, Chairman of the Board and Chief Executive Officer of Wisconsin Energy Corporation.

Gale E. Klappa

Elaine, thank you. Good afternoon, everyone. It's a whopping 9 degrees at downtown Milwaukee, but we're ready to warm you up as we review our 2013 year end results. Let me begin, as always, by introducing the members of the Wisconsin Energy management team who are here with me today. We have Allen Leverett, President of Wisconsin Energy; Pat Keyes, our Chief Financial Officer; Susan Martin, General Counsel; Steve Dickson, our Controller; and Scott Lauber, our Treasurer.

Pat, of course, will review our financial results in detail in just a moment. But as you saw from our news release this morning, we reported earnings of $2.51 a share for 2013. This compares with earnings of $2.35 a share in 2012. And I'm pleased to report that 2013, by virtually every meaningful measure, was an exceptional year for Wisconsin Energy. Operationally, we achieved a number of significant milestones. We were named America's most reliable utility. We also earned the best in the Midwest regional reliability award for the ninth time in the past 12 years.

In early 2013, J.D. Power ranked our company the #1 large utility in the Midwest for customer satisfaction among business customers. And by year end, we attained our highest overall customer satisfaction ratings in the past decade, probably our best ever.

From a financial standpoint, we continued to deliver solid earnings growth. We generated strong positive cash flow, and we made significant progress toward a dividend payout that is more competitive with our peers across the regulated sector. Of course, a number of factors contributed to our record financial performance in 2013. As always, the weather had an influence on our results. We experienced colder-than-normal weather in the first and fourth quarters of 2013, and the colder winter months more than made up for a return to normal summer temperatures across the Midwest.

In addition to the weather, the investments in our Power the Future generating units, a strong focus on cost control and our share repurchase program all contributed to our 2013 performance. I might add that our Power the Future investments have provided very significant benefits to our customers over the bitterly cold months of this winter. Sales of our generation over and above the demand from our retail and wholesale customers, otherwise known as sales for resale into the Mid-continent power market, were up 500% in the fourth quarter of 2013 and have continued at high levels throughout the month of January. Our new, efficient coal units performed exceptionally well as the price of natural gas rose in the Midwest, providing more evidence -- more concrete evidence of the benefits of the diversified fleet. I'm going to remind you that the margins on this sales for resale help our customers by reducing our fuel costs, and the capacity helps to keep the lights on and the energy flowing throughout the region.

Turning now to the state of the economy. Wisconsin's unemployment rate declined to 6.2% in December and remains well below the national average. In fact, the unemployment rate in Wisconsin is now the lowest it's been since 2008. Delivered electric volumes to our large commercial and industrial customers, excluding the iron ore mines, dropped by 2.6% in 2013 but rose by 1.1% in the fourth quarter. We saw strength in several sectors, including paper manufacturing, chemical production, primary metals and transportation equipment. Wisconsin now ranks 17th of the Chief Executive Magazine list of the best states to do business. That's up from 5 years ago when the state was down at a rank of 43rd.

In addition, we continue to see customer growth across our system. Compared to 2012, new electric service connections were up by 6.4% during 2013, and new natural gas installations rose by more than 15%. This reflects a rebound in the home building market and the volume of customers who are switching from propane to natural gas.

Now as you may recall from our last update, we were nearing the completion of a major construction project, our biomass-fueled power plant in Rothschild, Wisconsin. I'm pleased to report that the plant achieved commercial operation on November 8, on-time and on budget. As I've noted before, the biomass plant helps us to diversify our portfolio of renewable energy. The new unit produces electricity for the grid and provides steam for the Domtar paper mill, and we can dispatch the unit on demand. That's a benefit simply not available with solar or wind generation. Overall, our investment in the biomass plant totaled $269 million, excluding allowance for funds used during construction.

Over the past few months, we have also started a new construction project at one of our oldest hydroelectric plants. In October of 2013, we began building a new powerhouse at our Twin Falls hydro site. That's on the border of Wisconsin and the Upper Peninsula, Michigan. Twin Falls is 1 of 13 hydroelectric plants on our system. It was built back in 1912. And while the plant is licensed to operate until 2040, the existing powerhouse is badly in need of repair. We considered several alternatives, but the most prudent course is to build a new powerhouse and add spillway capacity to meet current federal standards. Since our last update, we began site work to prepare for the start of major construction activity, and the major activity is planned for the spring. We expect to complete the project in 2016, with an estimated cost of $60 million to $65 million, again excluding allowance for funds used during construction.

We're also planning to convert our Valley Power Plant from coal to natural gas. To refresh your memory, the Valley plant is a co-generation facility located along the Menominee River near downtown Milwaukee. Valley generates electricity for the grid, produces steam to heat more than 450 buildings in the downtown Milwaukee business center and provides voltage support for our distribution network. We received an air permit for the project in November of '13. And then just last week, the Wisconsin Public Service Commission gave its oral approval of the project, and we should receive a written order, a final written order, very soon. We plan to complete the Valley conversion in late 2015 or early 2016 at an estimated cost of $65 million to $70 million, excluding allowance for funds used during construction. Also, before we begin the conversion, we must upgrade the existing natural gas pipeline that runs near the facility. That upgrade began in March of this past year and has an estimated cost of $26 million. Converting Valley over to natural gas will reduce our operating costs and enhance the environmental performance of the units. We expect the electric capacity of the plant to remain at 280 megawatts, and we believe our plan will help support a vibrant downtown Milwaukee for many years to come.

Switching gears now. You'll recall that in 2011 our Board of Directors authorized us to repurchase up to $300 million of Wisconsin Energy common stock. That authorization ran through the end of 2013. So during 2013, we purchased approximately 3,025,000 shares. In total, since the program began, we've repurchased 7,877,000 shares at a cost just over $277.8 million. That equates, ladies and gentlemen, to an average purchase price of $36.19 a share.

In December, as you may recall, the board approved a new share purchase plan. The new plan authorizes management to purchase up to $300 million of Wisconsin Energy stock from 2014 through 2017. Regarding our dividend policy, last month, our board voted to raise the quarterly dividend of the company's common stock from $0.3825 a share to $0.39 a share. The new annual rate is $1.56 a share. This represents a 30% increase over the dividend rate that was in effect at the end of 2012. The board also reaffirmed the dividend policy that calls for a payout ratio of 65% to 70% of earnings in 2017, a level that will be more competitive with our peers across the regulated utility sector.

Now I'd like to touch on our growth plan and the investment opportunities that we see unfolding over the next several years. Our capital budget calls for spending $3.2 billion to $3.5 billion over the 5-year period 2014 through 2018. In this 5-year plan, we'd move from the large, very high-profile projects that were part of Power the Future to many smaller scale projects designed to upgrade our aging distribution infrastructure. Over this 5-year period, we'll be placing a greater focus on pipes, polls, wires, transformers and substations, the very building blocks of our delivery business. We're rebuilding 2,000 miles of electric distribution lines, replacing 18,500 power polls, 20,000 transformers and literally hundreds and hundreds of substation components.

On the natural gas side of our business, we're replacing 1,100 miles of gas mains, 83,000 individual gas distribution lines and some 233,000 meter sets. The primary risks associated with these projects, developmental, legal, regulatory, construction, are naturally more manageable given the smaller scale and scope of the distribution work. But this work is no less valuable or important than the megaprojects we have completed in recent years. Our focus on renewing our distribution network is essential to maintaining our status as one of the most reliable utilities in the nation.

And now I'd like to walk through our 10-year capital budget projection to provide you with additional clarity on our longer-term plans. As you can see in the earnings package on our website, over the 10-year period 2014 through 2023, our investment focus will remain on our smaller-scale distribution infrastructure projects. We currently estimate our total capital spend over this period will be in a range of $6.5 billion to $7.1 billion or between $650 million and $710 million a year. During the latter part of the 10-year period, we'll determine whether additional investments will be needed for us to continue meeting Wisconsin's renewable energy standard. We currently project to be in compliance through the year 2022.

Now it's important to point out that we expect the earnings growth from our 10-year capital investment plan to be supplemented by earnings growth in other areas, such as our 26% ownership of American Transmission Company and earnings growth from using our strong cash flow to fund additional investment opportunities, purchase shares or retire debt. Based on everything we see today, we believe our long-term earnings growth rate will be comparable to the best managed companies in our industry.

Now I'd like to briefly cover a few details about our near-term investment opportunities. For example, we continue to make progress on our fuel flexibility initiative at the Oak Creek expansion units. As you may recall, the units initially were permitted to burn bituminous coal. However, given the current cost differential between bituminous and Powder River Basin sub-bituminous coal, blending the 2 types of coal could save our customers between $25 million and $50 million a year depending upon the blend. After receiving environmental approvals, we began testing a blend of bituminous and Powder River Basin coal at the plant last May, and the initial tests are promising. We plan to continue testing into 2015 to identify equipment modifications that could be needed to increase the percentage of Powder River Basin coal permanently in our fuel mix. If significant modifications are required, we expect to seek approval from the Wisconsin Public Service Commission in late 2014 or early 2015.

As we look ahead, the investments we're planning on the generation side of our business, converting Valley to natural gas, changing our fuel mix at Oak Creek, are expected to lower cost for customers. The Valley conversion, for example, is projected to save $10 million to $15 million annually in operating costs. As I mentioned, our fuel flexibility efforts at Oak Creek could save customers up to $50 million a year depending on the coal blend.

On the natural gas side of our business, you may recall that we're planning to build a new natural gas lateral in west-central Wisconsin. We filed an application for approval with the Wisconsin Commission in 2013. A prehearing conference to set the regulatory schedule was held in December. This 85-mile line would run between Eau Claire County in the far Western part of the state in the city of Tomah in Monroe County in west-central Wisconsin. The project will address reliability concerns in Western Wisconsin and meet growing demand. Demand is being driven by 2 factors: customers converting from propane to natural gas and by the growth of the sand mining industry in that region. I might add that 9 communities along the proposed route have now passed resolutions authorizing us to begin operating natural gas distribution systems within their borders. If we receive timely approval from the Wisconsin Commission, we expect an in-service date during the fourth quarter of 2015. The projected cost is $150 million to $170 million, excluding allowance for funds used during construction.

Now as many of you know, and I'm sure there are some chattering teeth out there, this winter has been brutally cold in Wisconsin and the Upper Midwest. If they made a movie about the last couple of months, the title, I think, would be Polar Vortex Meets the Frozen Tundra. But movie or no movie, we delivered more natural gas to our retail customers during January than during any other single month in history. And this growth in demand underscores the need to expand our natural gas distribution network in Western Wisconsin.

We're also following another possible investment opportunity, the potential sale of the State of Wisconsin's electric and steam generating units. Last year, you may recall, Governor Walker signed into the law a new state budget, and that budget includes a provision expanding the state's authority to sell or lease certain state-owned properties. This means that the administration now has the authority to pursue the sale of the state's electric steam and chilled water production and distribution facilities. The state is moving forward and, in October, officials began the process of selecting outside financial advisors. No formal timetable has been announced, but if the sale does take place, we expect that it would occur in early 2015.

And finally, before closing my remarks, I'd like to provide an update on our operations in Michigan. As you'll recall, under Michigan law, retail customers may choose an alternative supplier to provide power supply service. The law limits customer choice to 10% of Michigan's retail sales, but the law excludes from the cap the iron ore mines in Michigan's Upper Peninsula. The 2 iron ore mines we've been serving on a low margin interruptible tariff switched to an alternative supplier in September of '13. Several smaller customers have switched as well. Of course, we continue to provide distribution and customer service functions regardless of the power supplier. We have taken and we'll continue to take multiple steps to address the situation. We filed a request with the mid-continent grid operator to suspend the operations of all 5 of our units in the Upper Peninsula. That's at the Presque Isle Power Plant. In October of last year, MISO determined that all the units are still required to maintain reliability in Northern Michigan. As a result, we are eligible for system support resource payments from MISO to recover the costs that we incurred to operate the units.

Since our last update, we have now finalized system support resource agreement with MISO. Under the agreement, MISO will pay us an availability fee to ensure the units are maintained and available to run and a fee to cover our costs when the units are actually operating. MISO recently filed this agreement with the Federal Energy Regulatory Commission. And following FERC approval, we expect to receive payments retroactive to February 1 2014. Although the long-term impact of the Michigan choice law is still uncertain, we expect that successful mitigation efforts on our part and a reasonable regulatory response should make our net financial exposure immaterial.

That said, given the loss of load in Michigan's Upper Peninsula, we are reevaluating our supply portfolio. Before the departure of the mines, we had a long-term need for at least a portion of the Presque Isle plant. At this point, we do not have such a need. As you may recall, we were working with Wolverine Power Cooperative, a power coop in Michigan, to determine if we could modify the structure of our joint venture to address the new circumstances. However, we were not able to find an alternative that would work for both Wolverine and for our customers. As a result in December, we agreed to terminate the joint venture. We'll continue to review the long-term options for the plant, including its potential sale.

In summary, ladies and gentlemen, we enter 2014 in excellent condition. The company is performing at a high level, both operationally and financially. Our Power the Future investments are providing very significant and tangible benefits for our customers and stockholders, and we'll continue to focus on renewing and upgrading our distribution network as we deliver the future.

And now with more details on our full year performance and our outlook for 2014, here's our Chief Financial Officer, Pat Keyes. Pat?

James Patrick Keyes

Thank you, Gale. As Gale mentioned, for 2013, our earnings rose to $2.51 a share, compared with $2.35 a share for 2012. Consistent with past practice, I will discuss operating income for our 2 business segments and then discuss other income, interest expense and income taxes. Our consolidated operating income for the full year 2013 was $1,080,000,000 as compared to $1 billion even in 2012. That's an increase of $80 million. Starting with the utility energy segment, operating income in 2013 totaled $719.4 million, an increase of $71.7 million over 2012. On the positive side, we estimate the cold winter weather increased our margins by $82.3 million. 2013 was unusually cold in the first and fourth quarters and, in 2012, we experienced a very mild first quarter.

Pricing increases for our Wisconsin retail customers net of amortizations also helped by $57.8 million. Conversely, we estimate that the return to normal summer weather in the second and third quarters reduced our margins by $35.9 million when compared to the unusually hot summer of 2012. In addition, depreciation expense increased by $23.8 million, with the additional capital investment placed in service during 2012.

In December of 2013, we filed a request with the federal government for a treasury grant related to our newly completed biomass plant. The grant was neutral to our net income because our Wisconsin retail customers received bill credits during the year. As discussed in prior calls, the grant did boost our fourth quarter income.

Now turning to our non-utility segment. Operating income was up $8.3 million when compared to last year because of the final approval of our Power the Future plant costs in the last Wisconsin rate case. Taking the changes for these 2 segments together and a slight decrease at corporate and other, you arrive at the $80 million increase in operating income.

During 2013, earnings from our investment in the American Transmission Company totaled nearly $69 million, up almost $3 million from 2012. These earnings were in line with our expectations. Our other income, net declined by $16 million, primarily because of lower AFUDC. AFUDC decreased because we completed the final stages of the air quality control system for the older Oak Creek units in 2012.

Our net interest expense increased by $3.9 million. This was primarily driven by lower capitalized interests as we had fewer construction projects underway in 2013. Our consolidated income tax expense rose by $31.6 million because of higher pretax earnings and a slightly higher effective tax rate. The higher effective tax rate was driven primarily by lower tax benefits and lower equity AFUDC which are permanent differences for income tax purposes. Our effective tax rate for 2013 was 36.9%, compared to 35.9% in 2012. We estimate that our effective tax rate in 2014 will be 37.5% to 38.5%.

Combining all of these items brings you to $577.4 million of debt income for the year. Including $0.03 for the cumulative effect of our share repurchases, we earned $2.51 per share. During 2013, our adjusted operating cash flows totaled $1,234,000,000, which is a $17 million increase from 2012. The increase came partly from higher net income and the fact that no contributions to our benefit plans were required in 2013 compared to $100 million contribution made in 2012. Partially offsetting these items was an increase in working capital.

Our capital expenditures totaled $687.4 million in 2013, a $19.6 million decrease compared to 2012. We saw lower expenditures because construction on the air quality control system for the older Oak Creek units was completed in 2012. This was partially offset by additional capital expenditures related to the biomass project.

We also paid $328.9 million in common dividends in 2013 which was $52.6 million greater than in 2012. And as Gale mentioned earlier, in January, the board increased our quarterly dividend to $0.39 per share, which raised the annual dividend rate to $1.56 per share.

We are also pleased that our adjusted debt-to-capital ratio was 52.5% at the end of 2013 which is lower than our 2012 ratio of 53.2%. We expect 2014 will be in line with 2013. We are using cash to satisfy any shares required for our 401(k) plan, options and other programs. So that going forward, we do not expect to issue any additional shares.

As Gale mentioned earlier, delivered electric volumes to our large commercial and industrial customers, excluding the iron ore mines, dropped by 2.6% in 2013 but rose 1.1% in the fourth quarter. Delivered electricity reflects the demand from both our retail and electric choice customers and thus, is a good indicator of how the regional economy is faring. But consistent with past practice, I will also report on traditional sales to our retail customers. These sales statistics include both supply and distribution service. As shown in the earnings package on our website, retail sales electricity, excluding the mines, declined by 1.6% during 2013 as compared to 2012. Weather-normalized sales were down 0.7%.

Looking at the individual customers segments, we saw actual residential sales decrease by 2.1% in 2013. On a normalized basis, residential sales declined by 3/10 of 1%. Across our small commercial industrial group, actual annual sales were flat with 2012 levels. And on a weather-normalized basis, full year sales to this group were down by 3/10 of 1%. Sales to the large commercial industrial segment for the full year 2013, excluding the iron ore mines, were down 3% for the year but were stronger in the latter half of the year.

Overall, for 2014, we're forecasting a 1/10 of 1% decrease in weather-normalized sales, again, excluding the iron ore mines. We expect residential sales to grow 4/10 of 1%, impacted by continued modest growth in housing starts offset by conservation.

In the small commercial industrial segment, we are projecting a slight increase of 1/10 of 1%. And in the large commercial industrial group, we are projecting a decrease of 8/10 of 1%. On the other hand, if we look at delivered electric volumes, we're projecting a 1/2 of 1% increase.

On the natural gas side of the business, total volumes in 2013 increased by 9.9%, primarily due to colder weather. On a normalized basis, and excluding the volumes used in power generation, gas volumes increased by 2.4% compared to 2012. This is attributed to an increase in customers, the old switching to natural gas and the positive impact of additional gas used in the sand mining industry.

Looking over the period 2014 through 2018, we're projecting positive free cash flow totaling $500 million. As a reminder, we define free cash flow as the cash available after capital spending and dividends.

Next, I'd like to announce our earnings guidance for 2014. As we've discussed, our earnings in 2013 were $2.51 a share. Subtracting $0.09 for favorable weather and then adding back increased O&M spending partly related to the weather, we estimate that normalized earnings for 2013 were $2.48 a share. Taking this into account, we expect our earnings for 2014 to be in a range of $2.53 a share to $2.63 a share. Our 2014 earnings projection assumes normal weather. And again, our guidance for 2014 is $2.53 a share to $2.63 a share. And finally, as we look ahead and taking into account our cold January weather, we expect our first quarter 2014 earnings to be in a range of $0.79 to $0.81 a share.

And with that, I'll turn things back to Gale.

Gale E. Klappa

Pat, thank you very much. Overall, we're on track and focused on delivering value for our customers and our stockholders.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Jim von Riesemann with CRT Capital.

James D. von Riesemann - CRT Capital Group LLC, Research Division

I'm confused. So the question is, you indicated that your 4% to 6% targeted growth rate, you -- that's was your historical growth. And today, you said you want to be amongst the best managed companies in terms of growth going forward. So what do I make of that statement? It was very wide open.

Gale E. Klappa

Okay. Well, let me walk you through our thinking. First of all, as you know, we -- as promised, we published today for all of you a 10-year capital spending plan to give everyone a little bit better clarity on the investment opportunities that we see, particularly in our retail utilities going forward. When we look at those investment opportunities, which are real, when we look at several other opportunities -- investment opportunities that may or may not come to pass but we're working on, when you factor in the growth from American Transmission Company and factor in potential uses of our strong cash flow, as I say, we have no reason today to change our long-term earnings growth forecast and I personally think that, that forecast will place us among the best managed, best growing companies in the industry.

James D. von Riesemann - CRT Capital Group LLC, Research Division

Okay, super. Second question is, with this revised 10-year CapEx plan, you talked about depreciation now being in the range of, I think, $425 million a year or so on average versus $375 million previously. What does that do to rate base growth, and could you all talk about how that depreciation plays out and what your rate base growth forecasts are?

Gale E. Klappa

Well, if you -- I think a pretty simple way to look at that is if you start with where we are today, where our utility rate base, is about $6.6 billion at the end of 2013. We're projecting out to grow to $7.1 billion of rate base by the end of '15. And then you can just do the math in terms of looking at that lifesaver chart we have for 10 years, and then taking the $425 million of average depreciation. So you can see what the utility -- the basic utility rate base growth looks like in terms of capital investment above the rate of depreciation.

James D. von Riesemann - CRT Capital Group LLC, Research Division

Okay, and then just one last question. Can you talk a little bit about deferred taxes and what you expect going forward?

Gale E. Klappa

Sure, we'll be happy to do that. Pat and Steve have all the information on deferred taxes going forward.

Stephen P. Dickson

Yes, I think -- this is Steve Dickson. In the past, we had said that because of bonus depreciation, because of the PLR on Road, we had significant tax deductions which created significant deferred taxes, and cash taxes were low this year. And we expect to have NOLs going into 2014, which will reduce tax carry for -- or reduced cash taxes in 2014 and also into 2015. And we will have, when we file the 10-K, the detailed schedules of our NOL carryforwards and long-term deferred tax items.

James D. von Riesemann - CRT Capital Group LLC, Research Division

Okay. I'm still confused a little bit, Gale. So I want to go back to the first question, if you guys don't mind and then I'll turn it over to somebody else. So when you're talking about this growth rate, I guess the first question is, who are you comping yourselves against? How does that growth rate accelerate going forward, and where might you be conservative on that growth rate guidance?

Gale E. Klappa

Well, I would look at it more who's copying us, Jim, but then I'm biased. I mean, clearly, we think we can deliver the best customer value and best shareholder value by focusing our investments on our core business. So point number one, which you've heard me reiterate time and time again is, we do not intend to diversify into unregulated businesses or to golf courses in Mexico. I mean, we're going to focus on our knitting. We're going to excel at managing investment projects and bringing them in for customers on-time and on budget. We're going to continue to try to be the most reliable utility in the nation, and that's our basic strategy. And from that strategy, we believe, at the moment, that our medium-term growth rate is 4% to 6%.

Operator

Your next question comes from the line of Kit Konolige with BGC Financial.

Kit Konolige - BGC Partners, Inc., Research Division

So to follow a little bit on Jim's line of questioning about the growth rate, what are you expecting out of ATC? If you look out 5 or 10 years, what do you think is reasonable to think when it translates into Wisconsin Energy earnings, how much of a growth rate there can be there?

Gale E. Klappa

Well, Allen, who's on the ATC board will give you the answer to that question. Just to frame it, though, through the past several years, the growth rate of ATC has been very supportive of our corporate-wide 4% to 6% growth rate. Allen?

Allen L. Leverett

Yes, Kit, this is Allen. I guess when you look at ATC, their projected rate base this year -- so 2014, their projected rate base is about $3 billion. And if you look at their 10-year capital spending plan solely for their traditional footprint, so their traditional service territory, if you will, in Wisconsin as well as in Michigan, they're projecting somewhere between $3 billion and $3.6 billion worth of capital over the next 10 years. So if you superimposed $3 billion to $3.6 billion on top of $3 billion of the current rate base, I mean, that gets you really to the mid to the upper end really of a 4% to 6%. So it's very, very supportive, meaning, net income growth rate. So it's very supportive of our Wisconsin Energy target. And then -- and although we're not including anything, Kit, over the next 3 years for additional net income contribution from projects outside of ATC's footprint, to the extent they can do some things outside their footprint, that will just go on top of really inside their footprint growth rate that's already supportive of 4% to 6%. Hopefully, that's responsive to your question.

Kit Konolige - BGC Partners, Inc., Research Division

Yes, absolutely. So if they do find -- or even adding that amount of rate base and especially if they go outside the footprint to find new projects, does that require additional equity contributions from you guys?

Allen L. Leverett

Well, the internal cash flow at ATC is very, very strong. So for the stuff inside the footprint, Kit, I would expect fairly minimal capital contributions being required. Now if they kill something and bring it back to the cave from outside the footprint, those -- some of those are pretty significant investments, and that would require some capital contributions from us as well as the other owners.

Kit Konolige - BGC Partners, Inc., Research Division

Right. Okay, fair enough. Good, I appreciate that. And one other area I'd like to just touch on for a second. When -- Pat, I think you were talking about sales growth. Those numbers you gave were for your 2014 estimate of sales growth. Is that correct?

James Patrick Keyes

Yes, Kit, that's correct. The -- I mean, I kind of walked through the deltas for '13 and then moved on to '14. So I'll just clip through them real quick. So overall, it was 0.1% decrease of normalized sales, so basically flat. With residential, up about 4/10; small commercial, down -- excuse me, up about a 1/10; and then the large C&I, down about 8/10.

Kit Konolige - BGC Partners, Inc., Research Division

And how about if you took a view of, say, 5 years? What would your growth rates look like?

James Patrick Keyes

Yes. I think we've kind of said over a 5-year horizon. We're looking at a long-term flattish to maybe 0.5%. Again, that's on the electric side.

Kit Konolige - BGC Partners, Inc., Research Division

Right. And how about on the gas side? I assume that's more robust.

James Patrick Keyes

Well, the gas side, yes, it's been interesting. I mean, if you look back from 2011 to 2012, normalized gas, we grew 1.3%-ish, and we're 2.4% 2012 to 2013, so I still don't trust our normalization completely. I mean, it was real warm here in 2012 and really cold last year. But if you look at -- since 1970s, say, that's been clear use for customers than on a steady decline. I think it's -- at minimum, we've leveled off, and you could probably make an argument that it may be creeping back.

Gale E. Klappa

And I would guess, to Pat's point, that the growth rate in individual customer use of natural gas, going forward, is going to depend upon whether or not gas prices stay in a reasonable and relatively stable zone, so we will see. But clearly, I think Pat is right. The outlook, in terms of growth in natural gas consumption, is stronger right now going forward than what I hope is a conservative assumption on our part on the electric side.

Operator

Your next question comes from the line of Jonathan Arnold with Deutsche Bank.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

My question was answered, but thank you.

Operator

Your next question comes from the line of Michael Lapides with Goldman Sachs.

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

Can you quantify -- since it's a public filing, meaning it's at the FERC, the data should be available. Can you quantify the MISO payments and how long you expect to receive that?

Gale E. Klappa

Sure, I'll ask Allen to quantify. There are 3 pieces to the MISO payments, and I will say upfront that under the MISO protocol, these agreements are for 12-month periods with renewal potential after each 12-month period. So 3 pieces to the MISO payments that have been filed. Allen?

Allen L. Leverett

Yes. And I guess maybe just to simplify, maybe just talk about it, and the 2 components that Gale talked about. But yes, there is a fixed component, Michael, which for a 12-month period, the fixed component would be approximately $52 million. And then, as Gale mentioned, when they dispatch the units, they would pay us essentially whatever the variable cost of operation is. So $52 million of 6 payments over a 12-month period, so 12 monthly payments, and then a variable component based on the operating costs. And Michael, the operating costs of the unit is on the order of $30 a megawatt hour, approximately.

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

How should we think about that? And I'm thinking about it from a bridge, from 2013 to 2014, to think about what of the $52 million. Let's just say, on hypothetical, it never dispatched, so we're just doing fixed cost recovery. How we should -- how should investors think about what the impact of that is year-over-year?

Gale E. Klappa

Maybe, Michael, we could step back a second and take that little bit different hypothetical because that -- those units are dispatched virtually all the time. At least [indiscernible] units are dispatched virtually all the time. So I'm not sure starting at a point where they don't get dispatched is particularly helpful. Maybe the best way to look at it is that iron ore mines switched supplier September 1. The cost to us, without any reimbursement whatsoever from MISO as we just continued to dispatch the units and basically, covering our fuel costs, the cost was about $0.01 a month, $0.01 a share or about roughly $4 million a month.

Allen L. Leverett

Yes. So Michael, as you step back, of course, 4 times 12 is 48. I mean, you -- the $52 million and the $40 million M&Ls offset each other.

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

Right. So are you basically saying that the bottom line impact of this is pretty much negligible for you, or is there actually a little bit of an uptick from this because you lost the $0.04 -- the $0.01 a month from September to December? And you would get that $0.04 back effectively but not incremental?

Gale E. Klappa

We do not get the $0.04 back from September through December, nor will we get compensated other than what we get on the hourly market in January. Remember, these payments are effective assuming FERC approval February 1. So I think we're all kind of looking at each other. I don't see any real uptick here. It's about awash.

Allen L. Leverett

Yes. Because you get 11 months of the fixed payments, Michael, and then we talked about the $4 million a month loss from the mines.

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

Got it, okay. I'll follow up with Pat offline on this one. Allen, one question on ATC. We've talked over the years multiple times about whether alternative ownership structures for ATC make sense. And one of the things -- given just where other pure play and there's only 1 or 2 transmission companies or even pipeline companies we trade, one of the things I don't know if we've talked about is whether an alternative structure similar to like a REIT-like structure for ATC would be value enhancing or value destroying for Wisconsin Energy and some of the other companies who own it.

Allen L. Leverett

Yes. Well, I did not know that electric transmission, I don't know if this a verb, but is REIT-able. Whether you could put that into a REIT or in some sort of master-limited partnership. So I wasn't aware that you could put electric transmission in that kind of structure, so I can't really comment on that in detail, Michael. But as I step back, I mean, in terms of ownership structure, I mean, we and the other owners, I mean, we certainly have the cash flow to fund the growth. And as I mentioned, in response to Kit's question earlier, it's quite accretive to our growth rates from our retail business. So we still think it fits, and it fits pretty well in terms of the current ownership structure.

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

Got it, last question. Gale, expectations for the rate case this year and just kind of what may be some pushback from intervenors could be? I know it's early.

Gale E. Klappa

It's very early. As everyone probably knows, Wisconsin is on a 2-year cycle, so this would be our normal bi-annual case. We would expect to file it in the spring, and we're putting together all the details as we speak. But I would suspect that the rate request will be very modest. And in addition to that, given the very strong performance of our generating units in the MISO market during the past year, I would expect that, that rate request will also include a fuel refund to customers.

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

Got it, so almost a negligible impact for the customer?

Gale E. Klappa

I wouldn't say negligible, but very modest.

Operator

Your next question comes from the line of Paul Ridzon with KeyBanc.

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

I just had one detail question. Your projected consumption expectations for '14, you said $0.8 down on large C&I, but then there was a follow-up comment, some offsetting which would be up 0.5%? I missed that commentary.

Gale E. Klappa

Yes. What we're trying to do is kind of break out 2 things for the first time because we have now experienced, in Michigan, some customers moving to alternative suppliers. So what we're trying to do is report traditionally the way we have reported, and the 0.5% up that you're asking about is on total delivered volumes. So whether they're our supply customer or not, we still provide distribution and customer service functions to those customers. So we wanted to show you kind of from an economic standpoint or a broader economy standpoint what the world kind of looks like to us, and we're projecting 0.5% weather normal growth in delivered volumes. Then the other statistics that Pat walked through in terms of large commercial and industrial, small commercial and industrial and residential, where we're projecting a slight decrease, those are the way we would traditionally have reported both supply and distribution customer sales. Am I making any sense to you, Paul?

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

The megawatt-hours delivered will exceed megawatt-hours generated to certain large C&I? You'll still deliver, but someone will also generate it?

Gale E. Klappa

That is correct. And if you look at it that way, megawatt-hours delivered will exceed megawatt-hours generated except a lot of those megawatt-hours are coming from our Presque Isle plant. So...

Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division

Intermediary in there somewhere?

Gale E. Klappa

Intermediary, that's a very, very good way to look at it.

Operator

Your next question comes from the line of Nathan Judge with Atlantic Equities.

Nathan Judge - Atlantic Equities LLP

Just a couple of things on -- questions on your capital spending. When looking at your delivery gas expectations, you just made a bunch of comments about how things are -- well, first of all, it's very cold; and then second, you've had a lot of talents along the route of your new pipeline sign up for an LDC agreement. And you also have talked in the past about the success of frac-ing. I'm just wondering, first of all, number one, is there an opportunity to upsize that investments? And number two, I don't think I see anything out for us that could phase even though it seems like there are some higher growth rate coming through from delivery. Just -- could you talk through that and give me some perspective on that?

Gale E. Klappa

Yes, I'd be happy to. The application we've made, Nathan, as you know, for approval for an 85-mile extension of our natural gas distribution network in the Western part of the state, that application -- depending upon how the factors in terms of customer demand continue to shake out, if approved, that application could be the first phase, if you will. And we're talking in Phase I here of this 85-mile line at a $150 million to $170 million investment. I would hope that we would receive approval from the Wisconsin Commission midyear this year to begin work later in the year. And I will tell you, what we experienced in the western part of the state over the course of January has done nothing but underscore the need, as I mentioned in our prepared remarks, for this extension. We saw a Canadian -- TransCanada pipeline explode a couple of weekends ago in Canada, near Winnipeg. And that affected the flow of gas off the major pipelines into the Dakotas, Minnesota and the western part of Wisconsin. Luckily, we were able to work our way through that without customer interruption. But when that happened, the windshields were in the minus 40- and minus 50-degree area. So you're talking about life and death kind of circumstances. And as I say, the experience of this past month has done nothing but underscore the need. So we're optimistic that we will get approval in a timely way from the Wisconsin Commission. And then depending upon future demand growth, as I mentioned, that could be -- this $150 million to $170 million project could be the first of 2 phases. But we'll take it one step at a time, and we hope to have -- we hope to be able to begin construction and have this first phase in place by late '15 or early '16. Does that respond to your question, Nathan?

Nathan Judge - Atlantic Equities LLP

It does. Just trying to see if the $150 million could be perhaps upside in the near-term, given what seems to be a very favorable backdrop.

Gale E. Klappa

I mean, it's certainly possible, but I wouldn't expect that for 2015 or 2016. Maybe later in 2016 or 2017.

Nathan Judge - Atlantic Equities LLP

And just a little bit on the fuel blending. I believe, if I recall correctly, that you were thinking about perhaps making a filing with the commission about possible investments in 2014, and it now sounds like you're looking at 2015. Has there been a change there, and what -- on the margins, what's going on?

Gale E. Klappa

No real change. We've been always saying that we want to be deliberate with our testing to make sure there's no degradation of the units and to be certain of what equipment modifications really might be needed for the long term. And our plan had always been to file for anything we might need in terms of commission approval related to the fuel blending in late '14 or early '15, so that is absolutely on track, Nathan.

Nathan Judge - Atlantic Equities LLP

Okay, I missed this. So in the late '14 -- sorry. And then just going to the renewables post 2020, which is I know quite a ways away, but I wasn't clear. And your 10-year capital plan, if you've got the renewables at $250 million to $450 million, is that an additional amount on top of your $650 million to $670 million roundabout between in '21 to '23?

Gale E. Klappa

You are absolutely correct, Nathan. That, if it comes to pass, would be additional on top of all the bars and all the spending that you see on that page. So it would be on top of the roughly $650 million to $670 million a year.

Nathan Judge - Atlantic Equities LLP

Great. And then just finally, if you could walk us through the sale of -- potential sale of a plant. You mentioned that in your commentary, but it sounds like now something will happen in 2015. Just -- if you could just walk us, just kind of give us an update.

Gale E. Klappa

Well, I think the state continues to progress forward in its thinking, and our expectation is that they are in the final stage of determining which financial advisors they would like to hire. They put out an RFP for financial advisors in the fall. I know they have interviewed financial advisors, and my sense is that, in the next month or 2, they may choose their financial advisor, and then the financial advisor would help them organize the effort going forward. And that's why we're saying if the sale of state-owned assets takes place, it probably would occur, our guess would be, in 2015.

Nathan Judge - Atlantic Equities LLP

And would -- could those plants -- a lot of those plants need to run given the steam properties of the steam generation heating properties. Obviously, a lot of those plants are -- require capital investment for CapEx or for environmental ratings. Is that in your budget at all, or how would that play out as we look kind of 2017 and beyond?

Gale E. Klappa

It's a very good question, Nathan. And the direct answer is that would be investment upside. We have not assumed anything in the terms of capital spending for state-owned power plants. It would be an investment upside for us.

Nathan Judge - Atlantic Equities LLP

Could you give us an idea about the amount -- the plant, what kind of investment would be required for capital on environmental?

Gale E. Klappa

Nathan, because the state is not really at a point where any due diligence is -- has been allowed, we have, in our minds, put a placeholder, but it's simply a guesstimate, and we're guesting $250 million perhaps for an initial capital outlay to purchase the plants. But that's just simply a guesstimate at this point.

Operator

Your next question comes from the line of Dan Jenkins with State of Wisconsin Investment Board.

Dan Jenkins

I just have a couple of clarification questions and then a couple of others beyond that. But I think you'd mentioned you expect $500 million of free cash flow when you're calculating that after subtracting CapEx and dividends for 2014. Did I get that right?

James Patrick Keyes

2014 through 2018, Dan. It's over the 5 years.

Dan Jenkins

Okay. So what does 85 million -- or 85-mile pipeline for the gas line that you're talking about, is that reflective? Is that what's the boost is on your last slide there for the 2015 gas delivery? Is that in the $330 million? Is that what's causing kind of the jump up?

Gale E. Klappa

Yes. When you see that gas delivery bar increase, that is exactly right. That would reflect the big lump of capital spending that would be required to make progress on that project in that year.

Dan Jenkins

Okay. And then I was curious on that same slide, just to kind of to clarify. You showed 2013, that's a different amount than what you're showing on Page 5 on your cash flow statement. There, you're showing $687 million. I was wondering what the difference was there.

James Patrick Keyes

Yes. Dan, this is Pat. The difference on the -- what Allen affectionally calls the lifesaver chart, that $668 million is only in the utilities, and what you're looking on the cash flow statement would include Power the Future. That's the difference.

Dan Jenkins

So then -- companywide then, it could potentially be a little higher than this, than you're showing on the slide?

Gale E. Klappa

The numbers you're seeing in what we call the lifesaver chart, with the bars breaking down basically customer service generation, delivery and renewables, those bars reflect the spending that we expect in our retail utilities only. So there are additional investments that are planned, obviously, for our maintenance capital for the Power the Future units. We have a little bit of capital for some of the other business lines. But what we wanted to show you was the rate base growth that we see going forward here over the -- our best guesstimate over the course of the next 10 years. Does that respond to your question?

Dan Jenkins

Sure. So that would be incremental to the Slide 13?

Gale E. Klappa

That is absolutely correct.

Dan Jenkins

Okay. Going back to this, you mentioned on this pipeline that it would potentially -- that it would pass 9 communities that would potentially be interested in hooking on the gas service...

Gale E. Klappa

Dan, do you have a cabin out there or something?

Dan Jenkins

No, not yet, but I might. It sounds like it might be a good plan, but...

Gale E. Klappa

You pay, we'll hook you up.

Dan Jenkins

I was just curious what the potential -- like what's the population in that as far so we can get a sense for the potential growth.

Gale E. Klappa

Well, the -- these are -- as you know, Western Wisconsin is quite rural, so these are small communities, a couple of thousand people per community. But the real demand out there is really coming, as I mentioned, from 2 areas; One, potential customer growth from these communities; but secondly, overall demand growth. Propane is widely used, particularly by farmers and other businesses in that section of the state. So conversions from propane and then, of course, the tremendous growth of the sand mining industry. We've gone from something in the neighborhood of 10 sand mining and sand processing operations in 2010 to over 100 sand mining operations. Actually, Pat is saying it's a 115 licensed sand mining operations last year, and these sand mining operations have to drive the sand before it is shipped. And their preferred method for drying sand is very large natural gas-fueled dryers. So you're seeing sand mine -- you're seeing requests from sand mining operations for us to supply gas to their operations. We're seeing customers wanting to switch from propane. And you know, Dan, as you follow the news, there have been shortages of propane in more than 24 states. And the price of propane, if you can get it, particularly in Western Wisconsin, is just incredible. So we would expect the demand from customers wanting to switch to propane, we would expect that momentum to continue to grow even from where we've seen it over the past couple of years.

Dan Jenkins

Okay. And then I was just curious as far as your financing plan for '14. I know you have $300 million maturing, coming up here in April 1. I expect you plan to refinance that. And is there any additional debt that you would need to issue this year?

Gale E. Klappa

We'll let Pat handle that question for you.

James Patrick Keyes

Sure, Dan. Yes, you're right. We've got that 6% coupon, $300 million coming due late March, April. That one will be replaced late Q1, early Q2. Probably about $250 million is what we're forecasting right now. And then, we've also got -- you may recall that in 2013, at Wisconsin Gas, we had a $45 million bond retired. We've not replaced that. We didn't replace that last year, but we will -- forecasting we'll replace that this year probably. So I would say Q2, Q3, maybe $100 million at Wisconsin Gas.

Dan Jenkins

Okay. And then just the last, you mentioned fourth quarter that you did see some pickup x the mine. Should it see some pickup in your large industrial customers?

Gale E. Klappa

That is correct.

Dan Jenkins

Do you anticipate that to continue, or is that maybe a reflection of onetime items? Or how should we think about the economic growth going forward?

Gale E. Klappa

What I can tell you, because we -- I personally look at this data every week. What I can tell you is that through January, now it's been cold, obviously. And so there is some bit of -- some small amount of weather sensitivity, even with the large industrials. But if you take a look at the 17 industrial customer segments where we have significant customer presence and where we serve, we serve industrial customers in 17 different segments of the economy. Through January, 9 of those 17 segments continued to show growth.

Operator

Your next question comes from the line of Brian Russo with Ladenburg Thalmann.

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

Actually, my questions have been answered.

Operator

Your next question comes from the line of Andy Bischoff with Morningstar.

Andrew Bischof - Morningstar Inc., Research Division

When you look at 5-year growth expectations for load growth of half -- of flat to 0.5%, is that consistent across residential, industrial and commercial, or is there some variation there?

Gale E. Klappa

No, there is some variation. I mean, again, given the fact that in total retail, we're only projecting 0.5% growth. The variation is not huge, but there is some modest variation. It's got, I think -- we're probably projecting a little stronger growth in small commercial and industrial than in a large.

James Patrick Keyes

Yes, a little bit stronger in the small.

Gale E. Klappa

Yes. So the only -- it's pretty even except a little bit stronger growth in small commercial and industrial than in large.

Operator

Your next question comes from the line of Vedula Murti from CDP Capital.

Vedula Murti

Couple of a separate things. One, you talked about the cash flow profile to 5 years through 2018. I don't -- I apologize, I don't have the slides in front of me, but does the cash flow profile in terms of free cash flow generation changed much in the outer years given that you have a 10-year CapEx plan?

Gale E. Klappa

We'd certainly been very thorough about running our models through the next 5 and, as Pat mentioned, our cumulative total free cash flow for '14 through '18 is approximately $500 million. I can tell you that, based on what we're seeing further out -- and again a lot of assumptions have to go into the further out, your capital spending, your returns, the growth -- in none of those periods that we turned negative cash.

Vedula Murti

You did turn negative cash?

Gale E. Klappa

We do not turn negative. Not turn negative. We see positive free cash throughout the entire period.

Vedula Murti

Okay. And my second question is more industry. There's been a lot of press lately in terms of cyber threats to the grid and other types of risks to the system. One, I'm wondering kind of in terms of what type of capital expenditures or other things are you seeing, that the industry is seeing? And also tying to that, is there anything going on with regards to coming up with something to kind of mirror, like Price-Anderson, like in terms of risks associated with the nuclear accident, if something were to significantly happen to a part of the grid or to specific -- to a particular operating system?

Gale E. Klappa

Well, to your second question, Vedula, I don't see anything on the horizon related to the distribution networks across the country or the grids across the country. I don't see anything on the horizon that would even resemble Price-Anderson, nothing like that. That may not be a bad idea, but I don't see anything quite like that at all. And then in terms of investments that we're making related to cybersecurity, the answer is yes. We are making investments related to cybersecurity, relating to protecting our networks. I would be a little reluctant to get into the specifics of those investments. But particularly on the gas distribution side of the business, I think over the course of 5, 10 years from now, over the second half of the 5-year period, you will see an increasing amount of capital spend on just security for the gas distribution networks as new pipeline safety rules come into effect. But yes, there are ongoing investments, things that we are doing, both physical security and protection from cybersecurity.

Vedula Murti

I mean, is that going to be like in the -- just in like the tens and millions of dollars annually or could they end up being more material?

Gale E. Klappa

Right now, it is not the lion's share anywhere close to out of our capital budget, but I would say -- my own personal belief is that as we work out 3, 5 and 10 years, that type of investment will become more and more material.

Operator

Your next question comes from the line of Leon Dubov with Luminus Management.

Leon Dubov

A couple of quick clarifications. One thing, I think Pat said, when asked about ATC, is that isn't not assuming anything outside the footprint for the next 3 years. I'm just wondering sort of more than 3 years out, are you thinking that we may see something?

Gale E. Klappa

Well, that was the older less handsome version of Pat. That was Allen, and we'll [indiscernible].

Allen L. Leverett

We're often confused. The 3 years out, you're exactly right. We've not made any assumptions that ATC would make any additional investments outside the footprint. But I can tell you, certainly, past those 3 years, I mean, ATC is very actively pursuing projects. But at this point, we're just being very conservative about how we put our projections together, and we're not assuming that they get any of those projects. But I've seen, certainly, stuff that they're pursuing that's upwards of $4 billion worth of capital investment. So I would hope that they would get some of those projects. But at this point, we haven't included them in our financial forecast.

Gale E. Klappa

And when Allen said that they got something and bring it back to the cave, I'm assuming we'd have to heat the cave.

Leon Dubov

And then one other thing. If -- in the new CapEx projections, in '15, the generation proportion went up by I think $55 million or so. Is that the Oak Creek fuel stuff, or is that something different?

Gale E. Klappa

We're looking at our chart here.

Leon Dubov

I think it used to be $102 million in your last presentation, now it's $157 million.

Gale E. Klappa

I guess that's largely timing.

Allen L. Leverett

Yes.

James Patrick Keyes

Yes.

Gale E. Klappa

Yes. Everybody is saying -- everybody is agreeing. That's largely timing from the year-to-year as we've refined our forecast going out.

Leon Dubov

Yes, okay. So is the Oak Creek fuel blending in this forecast at all or...

Gale E. Klappa

Very small amount, roughly $25 million worth.

Leon Dubov

In what year?

Allen L. Leverett

It should be in 2015, I would imagine.

Gale E. Klappa

Yes, but not a huge amount.

Operator

Your last question comes from the line of Serena Dackey with UBS.

Michael Weinstein

Actually, this is Mike Weinstein. The renewable investments in 2021 to '23, is that just driven by RPS standards? Is that what you're...

Gale E. Klappa

Let me explain, and then Allen can add on anything he would like as well. The Wisconsin renewable energy standard requires statewide that 10% of retail sales come from renewables by the year 2015, but then that 10% stays in place. So if you have any load growth at all, you have to add increments of renewables to maintain your compliance with the law and with the standard. So as we -- if you think about how we've complied with the standard so far, we have built the 2 largest wind farms in Wisconsin. We have just finished, as I mentioned, on-time and on budget a significant investment in a biomass plant, and we've supplemented those investments with renewable energy credits. So as we look further out, and Allen you and I decided with Pat, that it wasn't prudent to just simply assume that we could continue to add increments with very low cost renewable energy credits that far out. So we need to start looking 2022 as the latest year we would be in compliance under our current projections for growth. We need to start looking down the road at what other potential renewable investments might work for our portfolio. Allen?

Allen L. Leverett

Yes. And that's, obviously, just a placeholder at this point, Mike. And I would expect that renewable technologies will -- they've changed a lot in the last 10 years, and I'm sure they'll continue to change over the next 10 years. So it's really just a placeholder at this point, but it's an indication that, at some point, we're going to need some additional renewable capacity in order to stay in compliance with the state portfolio standard.

Michael Weinstein

So up through that time, you're meeting it with renewable credits?

Allen L. Leverett

Well, really a combination. Gale mentioned the fixed investments that we made, so the biomass, the 2 large wind farms and some other smaller renewable investments. So we have that, plus we've been buying some renewable energy credits. So really, it's a combination of those 2, Mike.

Michael Weinstein

Is there any chance that you could pull that back and do it a little earlier or...

Gale E. Klappa

That depends upon load growth. I mean, if we -- if our load growth projections are conservative and renewable energy credits diminish in terms of their -- either their availability or their cost, then yes. But right now, that's our best guesstimate in terms of timing.

All right. Well, ladies and gentlemen, I believe that concludes our conference call for today. Thank you so much for participating. If you have any other questions, the famous Colleen Henderson is available in our Investor Relations office, and her direct line is (414) 221-2592. Thank you, everyone. Good night.

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