威斯康辛能源 (WEC) 2013 Q4 法說會逐字稿

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, and all participants are in a listen-only mode at this time. 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 opened 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 is my pleasure to introduce Mr. Gale Klappa, Chairman of the Board and Chief Executive Officer of Wisconsin Energy Corporation.

Colleen, thank you. Good afternoon, everyone. It is a whopping 9 degrees in downtown Milwaukee, but we are 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 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 number-one 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 midcontinent 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 would remind you that the margins on these sales for resale help our customers by releasing 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 has 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 on the Chief Executive magazine list of the best states to do business. That is up from five 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 homebuilding 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 am pleased to report that the plant achieved commercial operation on November 8, on time and on budget.

As I have 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 is 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 is on the border of Wisconsin and the Upper Peninsula of Michigan.

Twin Falls is one 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 have begun site work to prepare for the start of major construction activity, and the major activity is planned for this 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 cogeneration facility located along the Menomonee 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 2013; and then just last week, the Wisconsin Public Service Commission gave its oral approval of the project. And we should receive 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 will 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 have 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 repurchase 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 to $0.3825 to $0.39 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 five-year period 2014 through 2018.

In this five-year plan we have moved 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 five-year period we will be placing a greater focus on pipes, poles, wires, transformers, and substations -- the very building blocks of our delivery business. We are building 2,000 miles of electric distribution lines, replacing 18,500 power poles, 20,000 transformers, and literally hundreds and hundreds of substation components.

On the natural gas side of our business, we are 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, and 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 will 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 is 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 two 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 base. 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 costs 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 are 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 and 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 two 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 am 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 industry. And this growth in demand underscores the need to expand our natural gas distribution network in western Wisconsin.

We are 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 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 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 two iron ore mines we were serving on a low-margin interruptible tariff switched to an alternative supplier in September of 2013. 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 will continue to take multiple steps to address the situation. We filed a request with the midcontinent grid operator to suspend the operations of all five of our units in the Upper Peninsula. That is 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 we incur to operate the units.

Since our last update we have now finalized a 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. Following FERC approval, we expect to receive payments retroactive to February 1 of 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 co-op 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 will 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 will 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 is our Chief Financial Officer, Pat Keyes. Pat?

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 two business segments and then discuss other income, interest expense, and income taxes.

Our consolidated operating income for the full year 2013 was $1.080 billion as compared to $1 billion even in 2012. That is 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 that 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 held 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 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 year. As discussed in prior calls, the grant did boost our fourth-quarter income.

Now, turning to our nonutility 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 two segments together, at 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 interest, 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 net income for the year. Including $0.03 for the cumulative effect of our share repurchase, we earned $2.51 per share.

During 2013 our adjusted operating cash flows totaled $1.234 billion, 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 a $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 of 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're 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 of 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 customer segments, we saw actual residential sales decreased by 2.1% in 2013. On a normalized basis, residential sales declined by 0.3%.

Across our small commercial and 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 0.3%.

Sales to the large commercial and 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 0.10% decrease in weather-normalized sales -- again, excluding the iron ore mines. We expect residential sales to grow 0.4%, impacted by continued modest growth in housing starts, offset by conservation.

In the small commercial and industrial segment, we are projecting a slight increase of 0.1%. And in the large commercial and industrial group, we are projecting a decrease of 0.8%. On the other hand, if we look at delivered electric volumes, we're projecting a 0.5% 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 lines volumes increased by 2.4% compared to 2012. This is attributed to an increase in customers, fuel 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 are 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 would like to announce our earnings guidance for 2014. As we have 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 will turn things back to Gale.

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

(Operator Instructions) Jim Von Riesemann, CRT Capital.

It is as cold as ice, Jim, good line.

Mute button would help, right?

It was frozen! (Laughter)

It was frozen! Cold as ice. A little Foreigner action for you.

1977.

I am confused.

Well, you and Vinnie Barbarino. So confused. What can we help with, Jim?

Okay. So the question is: you indicated that your 4% to 6% targeted growth rate -- that's what 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.

Okay, well, let me walk you through our thinking. First of all, as you know, 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 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.

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 a year previously.

What does that do to rate-based growth? And could you all talk about how that depreciation plays out and what your rate-based growth forecasts are?

Well, 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 are projecting out to grow to $7.1 billion of rate base by the end of 2015.

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.

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

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

Yes, I think -- this is Steve Dickson. In the past we said that because of bonus depreciation, because of the PLR on Elm 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 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.

Okay. I am 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 will 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?

Well, I would look at it more of who is copying us, Jim, but then I am biased. 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 have heard me reiterate time and time again, is we do not intend to diversify into unregulated businesses or the golf courses in Mexico. 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 are going to continue to try to be the most reliable utility in the nation. And that is our basic strategy. And from that strategy we believe at the moment that our medium-term growth rate is 4% to 6%.

Okay, I will let it go. Thanks.

Kit Konolige, BGC Financial.

How's the shoveling been, Kit?

Shoveling is pretty good. You know, I don't bother shoveling. I just trip and fall.

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 it's reasonable to think? When it translates into Wisconsin Energy earnings, how much of a growth rate there can be there?

We will let Allen, who is on the ATC board, 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?

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 are projecting somewhere between $3 billion and $3.6 billion worth of capital over the next 10 years.

So if you superimpose $3 billion to $3.6 billion on top of $3 billion of current rate base, that gets you really to the mid to the upper end really of a $4 billion to $6 billion. So it is very, very supportive -- meaning a net income growth rate. So it is very supportive of our Wisconsin Energy target.

And then, although we are not including anything, Kit, over the next three years for this net income contribution from projects outside of ATC's footprint, to the extent they can do some things outside of their footprint, that will just go on top of, really, an inside-their-footprint growth rate that is already supportive of $4 billion to $6 billion. Hopefully that is responsive to your question.

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?

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, some of those are pretty significant investments. And that would require some capital contributions from us as well as the other owners.

Okay, fair enough. I appreciate that. And one other area I would like to touch on for second.

Pat, I think you were talking about sales growth. Those numbers you gave were for your 2014 estimate of sales growth. Is that correct?

Yes, Kit, that is correct. I walked through the deltas for 2013 then moved on to 2014. So I will just flip through them real quick.

So overall it was 0.10% decrease in normalized sales, so basically flat; with residential up about 0.40%; small commercial up about 0.10%; and then the large C&I down about 0.80%.

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

I think we said over a five-year horizon, we're looking at a long-term flattish to maybe 0.50%. Again, that is on the electric side.

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

The gas side, yes, it has been interesting. If you look back from 2011 to 2012, normalized gas we grew 1.3%-ish. And then we were 2.4% 2012 to 2013.

So I still don't trust our normalization completely. It was real warm here in 2012 and really cold last year. But if you look at -- since I think it was 1970, say, it has been clear use per customer has been on a steady decline. I think at minimum we have leveled off. And you could probably make an argument that it may be creeping back.

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.

Great. Okay. Well, thanks a lot, guys.

Jonathan Arnold, Deutsche Bank.

My question was answered, but thank you.

Michael Lapides, Goldman Sachs.

Looking forward to my invitation to an Analyst Day at a golf course in Mexico with you one day. (Laughter.) I will go check my mailbox daily for it.

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

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

And maybe just to simplify it, maybe just talk about it in the two components that Gale said about it. Yes, there is the 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 fixed payments over a 12-month period -- so 12 monthly payments -- and a variable component based on the operating cost. And Michael, the operating cost of the unit is on the order of $30 a megawatt hour, approximately.

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 the hypothetical, it never dispatched. So we're just doing fixed-cost recovery. How should investors think about what the impact of that is year over year?

Maybe, Michael, we should step back a second and take a little bit different hypothetical. Because those units are dispatched virtually all the time; at least [four of the] 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 suppliers September 1. The cost to us without any reimbursement whatsoever from MISO, as we just continued to dispatch the units and basically were covering our fuel costs, the cost was about $0.01 a month. $0.01 a share, or about roughly $4 million a month.

So Michael, as you step back, of course $4 million times 12 is $48 million. The $52 million and the $48 million -- they all offset each other.

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.

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

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.

Got it. Okay. I will follow up with Pat off-line on this one.

Allen, one question on ATC. We have 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 one or two transmission companies or even pipeline companies with trade -- one of the things I don't know if we have 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.

Yes. Well, I did not know that electric transmission -- I don't know if this is 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 you could put electric transmission in that kind of structure. So I can't really comment on that in detail, Michael.

But if I step back in terms of ownership structure, we and the other owners -- we certainly have the cash flow to fund the growth. And as I mentioned in response to Kit's question earlier, it is quite accretive to our growth rates from our retail business. So we still think it fits and fits pretty well in terms of the current ownership structure.

Got it. And last question. Gale, expectations for the rate case this year, and just what maybe some pushback from interveners could be? I know it is early.

It is very early. As everyone probably knows, Wisconsin is on a two-year cycle, so this would be our normal biannual case. We would expect to file it in the spring. And we are putting together all of 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.

Got it. So almost a negligible impact for the customer.

I wouldn't say negligible, but very modest.

Paul Ridzon, KeyBanc.

Just had one detail question. You had projected consumption expectations for 2014. 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.

Oh, yes. What we're trying to do is kind of break out two 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 are asking about is on total delivered volumes. So whether they are a supply customer or not, we still provide distribution and customer service functions to those customers. So we wanted to show you from an economic standpoint and a broader economy standpoint what the world looks like to us. And we're projecting a 0.5% weather-normal growth in delivered volume.

Then the other statistics that Pat walked through in terms of large commercial and industrial, small commercial and industrial, and residential, where we are 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?

So megawatt hours delivered will exceed megawatt hours generated to serve large C&I? You will still deliver it, but someone else will generate it.

That is correct. 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.

There's an intermediary in there somewhere.

Intermediary -- that is a very good way to look at it.

Nathan Judge, Atlantic Equities.

Just a couple of questions on your capital spending. When looking at your delivery gap expectations -- you just made a bunch of comments about how things are -- well, first of all, it is very cold; and then second, you have had a lot of towns along the route of your new pipeline sign up for an LDC agreement. And you also have talked in the past about basic stuff for fracking.

I'm just wondering -- first of all, number one, is there an opportunity to upsize that investment? And number two, I don't think I see anything out for a second phase, even though it seems like there's some higher growth rate coming through from delivery. Could you talk through that and give me some perspective on that?

Be happy to. The application we have 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 1 here of this 85-mile line at $150 million to $170 million investment. I would hope that we would receive approval from the Wisconsin Commission mid-year 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 of 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 wind chills 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 two phases. But we will 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 2015 or early 2016. Does that respond to your question, Nathan?

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

It is certainly possible. But I wouldn't expect that for 2015 or 2016. Maybe later in 2016 or 2017.

And just moving on to the fuel blending. I believe, if I recall correctly, that you were thinking about perhaps making a filing with the Commission about a possible investment in 2014. And it now sounds like you are looking at 2015. Has there been a change there? And what -- on the margins, what is going on?

No real change. We have been always saying that we want to be very 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 2014 or early 2015. So that is absolutely on track, Nathan.

Okay. I basically rolled it into late 2014. Sorry.

And then, just going to the renewables out post-2020, which is, I know, quite a ways away, but I wasn't clear. In your 10-year capital plan, you have got the renewables at $250 million to $450 million. Is that an additional amount on top of your $650 million to $670 million roundabout in 2021 to 2023?

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.

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

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 have 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 two they may choose their financial advisor.

And then the financial advisor would help them organize the effort going forward. And that is why we're saying if a sale of state-owned assets takes place, it probably would occur, our guess would be, in 2015.

And to 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 plans require capital investment for CapEx or for environmental reasons. Is that in your budget at all? Or how would that play out as we look out 2017 and beyond?

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

Could you give us an idea about the amount spent on the plants? What kind of investment would be required for capital on environmental?

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

Thank you. I really appreciate it.

Dan Jenkins, State of Wisconsin Investment Board.

First, I just have a couple of clarification questions, and then a couple of others beyond that.

I think you 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?

2014 through 2018, Dan. So over the five years.

Okay. So with this 85-mile pipeline for the gas line that you are talking about, is that reflected -- is that what the boost is on your last slide there for the 2015 gas delivery? Is that in that $330 million? Is that is what is causing that jump up?

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.

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

Dan, this is Pat. The difference on what Allen affectionately calls the lifesaver chart -- that $668 million is only in the utilities. What you are looking at on the cash flow statement would include Power the Future. That is the difference.

Oh, okay. So Company-wide, then, that could potentially be a little higher than this? The numbers shown the slide?

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 -- our best guesstimate over the course of the next 10 years. Does that respond to your question?

Sure. So that would be incremental to the Slide 13, then.

That is absolutely correct.

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 onto gas service.

Dan, do you have cabin out there or something?

No, not yet. But I might -- sounds like it might be a good plan.

You pay, and we'll hook you up.

I was just curious what the potential -- like, what is the population thus far, so we can get a sense for the potential growth?

Well, as you know, western Wisconsin is quite rural; so these are small communities. A couple thousand people per community.

But the real demand out there is really coming, as I mentioned, from two 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 have 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 is 115 licensed sand mining operations last year. And these sand mining operations have to dry the sand before it is shipped.

And their preferred method for drying sand is very large natural-gas-fueled dryers. So you are 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 from propane -- we would expect that momentum to continue to grow, even from where we have seen it over the past couple of years.

Okay. And then I was just curious as far as your financing plan for 2014. I know you have $300 million maturing coming up here April 1. I expect you plan to refinance that? And is there any additional debt that you would need to issue this year?

We will let Pat handle that question for you.

Sure, Dan. Yes, you are right. We have 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 have also got -- you may recall that in 2013, Wisconsin Gas -- we had a $45 million bond retire. We have not replaced that. We didn't replace that last year, but our forecasts say we will replace that this year, probably. So I would say Q2, Q3 maybe $100 million at Wisconsin Gas.

Okay. And you mentioned fourth quarter that you did see some pickup -- ex the mines, you did see some pickup in your large industrial customers.

That is correct.

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

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 has been cold, obviously; so there's 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 we serve we serve industrial customers in 17 different segments of the economy. Through January, 9 of those 17 segments continued to show growth.

Okay. That's all I had. Thank you.

Brian Russo, Ladenburg Thalmann.

Actually, my questions have been answered. Thank you.

Andy Bischof, Morningstar.

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

No, there is some variation. Again, given the fact that in total retail, we're only projecting 0.5% growth, the variation is not huge, but there is a modest variation. And Scott, I think we're probably projecting a little stronger growth in small commercial and industrial than in large?

Yes, a little bit stronger in the small.

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

Perfect. That's all I had left. Thanks.

Vedula Murti, CDP Capital.

A couple of separate things. One, you talked about the cash flow profile through five years through 2018. 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 change much in the outer years, given that you have a 10-year CapEx plan?

Well, we certainly have been very thorough about running our models through the next five. And as Pat mentioned, our cumulative total free cash flow for 2014 through 2018 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 did we turn negative cash.

You turn negative cash?

We do not turn negative --.

You do not. I apologize.

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

And my second question is more industry. There has been a lot of press lately in terms of cyber threats to the grid and other types of risks to the system. What I am wondering -- 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 mirror, like, Price-Anderson, in terms of risk associated with a nuclear accident, if something were to significantly happen to a part of the grid or to specific -- to a particular operating system?

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 five-year period, you will see an increasing amount of capital spent 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're doing -- both physical security and protection from cybersecurity.

Are they going to be, like, just in the tens of millions of dollars annually? Or could they be end up being more material?

Right now it is not the lion's share or anywhere close to it 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.

Thank you very much.

Leon Dubov, Luminus Management.

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

Well, that was the older, less handsome version of Pat. That was Allen.

I am sorry.

I'm going to let Allen answer the question now.

We're often confused for each other.

It's a long call.

The three years out -- you are exactly right. We have not made any assumptions that ATC would make any additional investments outside the footprint.

But I can tell you, certainly, past those three years, 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 have seen, certainly, stuff that they are pursuing that is 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 forecasts.

Okay.

So when Allen said if they got something and then bring it back to that cave, I am assuming we would have to heat the cave. (laughter)

And then one other thing. In the new CapEx projections, in 2015 the generation portion went up by, I think, $55 million or so. Is that the Oak Creek fuel stuff, or is that something different?

We're looking at our chart here.

I think it used to be $102 million in your last presentation. Now it is $157 million.

My guess is that is largely timing. Yes, everybody is agreeing. That is largely timing from year to year as we have refined our forecast going out.

Okay. So is the Oak Creek fuel blending in this forecast at all, or --?

A very small amount. Roughly $25 million worth.

In what year?

It should be in 2015, I would imagine.

Yes. But not a huge amount.

Got you. Okay, thank you very much. I will see you in a couple of days in Vail..

Serena [Dechi], UBS.

Actually, this is Mike Weinstein.

The renewable investments in 2021 to 2023: is that just driven by RPS standards -- is that what you are --?

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 have complied with the standard so far, we have built the two 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 have 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 of very low-cost renewable energy credits that far out. So we need to start looking, as 2022 is 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?

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

Up through that time you are meeting it with renewable credit?

Well, really a combination. Gale mentioned the fixed investments that we have made. So the biomass, the two large windfarms, and some other smaller renewable investments. So we have that; plus we have been buying some renewable energy credits. So, really, it is a combination of those two, Mike.

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

Well, it depends upon load growth. If our load growth projections are conservative and renewable energy credits diminish in terms of -- either of their availability or their cost, then yes. But right now, that is our best guesstimate in terms of timing.

Okay, thank you very much.

You are more than welcome. You take care.

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. Thanks, everyone. Good night.