埃克西爾能源 (XEL) 2015 Q3 法說會逐字稿

Good day and welcome to the Xcel Energy third-quarter 2015 earnings conference call. Today's conference is being recorded.

At this time, I would like to turn the call over to Paul Johnson, Vice President of Investor Relations. Please go ahead.

Thank you. Good morning and welcome to Xcel Energy's 2015 third-quarter earnings release conference call. Joining me today are Ben Fowke, Chairman, President and Chief Executive Officer; and Teresa Madden, Executive Vice President and Chief Financial Officer. In addition, we have other members of the Management team in the room to answer questions.

This morning, we will update your on recent regulatory and business developments, review our 2015 third-quarter results, discuss our 2015 and 2016 earnings guidance range. In addition, there are slides that accompany today's call that are available on our web page. We will also post a video on our website of Teresa summarizing financial results.

As a reminder, some of the comments during today's conference call may contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and our filings with the SEC.

I will now turn the call over to Ben.

Thank you Paul, and good morning. Today, we reported earnings of $0.84 for the quarter, which was $0.11 per share higher than last year.

With nine months of the year completed, we are very confident in our ability to hit our 2015 ongoing earnings guidance and are narrowing the range to $2.05 to $2.15 per share. We also initiating 2016 ongoing earnings guidance of $2.12 to $2.27 per share.

As we previously discussed, legislation was passed this year in Minnesota that contained several notable enhancements to the regulatory framework. The legislation expands the length of multi-year plans to up to five years, allows for a more formulaic approach to recovering capital investment, provides for a recovery of O&M expense based on an industry index and allows rider recovery of distribution costs that facilitate grid modernization.

Earlier in September, I had the opportunity to discuss with the Minnesota Commission and other stakeholders our vision of the future for the utility industry. The vision I outlined included adding cost-effective renewables to our system, adopting new technology like battery storage, modernizing our distribution grid and making it more resilient and ready for two-way energy flows, becoming more consumer centric and offering additional products, options and services that our customers want, changing our fleet to position us for the future, address the Clean Power Plan and significantly reduce carbon emissions.

I also discussed the recently passed legislation that gives us a new set of tools to use as we look to meet the challenges and opportunities of the future while providing significant benefits for consumers, investors and policymakers.

The multi-year plan provides greater certainty and transparency for both the Company and our customers. It also provides a longer runway to transform our cost structure and allows us to address significant energy policy issues which can be difficult to do when you're in a litigated rate case proceeding. Overall, I appreciated the opportunity and thought the meeting went well.

Consistent with our vision of the future, we recently filed an update to our Minnesota resource plan. The proposed plan now achieves a 60% carbon reduction for the NSP system by 2030 and includes the following key components. The retirement of Sherco Unit 2 in 2023, Sherco Unit 1 in 2026, the addition of 800 megawatt of wind and 400 megawatt of large-scale solar between 2016 and 2020, the addition of 1000 megawatt of wind and1000 megawatt of large-scale solar between 2020 and 2030, and finally, the addition of a 230 megawatt combustion turbine unit in North Dakota and a 780 megawatt combined cycle unit at the Sherco site in the mid-2020s.

This is an exciting plan that has widespread stakeholder support. It also is a continuation of our proactive environmental leadership strategy, which leaves us well positioned to meet the requirements of the EPA's Clean Power Plan. I believe this plan will create ownership opportunities for Xcel Energy as well.

The recently passed legislation, our proactive resource plan filing and our plans to file a multi-year rate plan in Minnesota are all part of our strategy to streamline the regulatory process so we can focus on longer-term energy policy issues.

In early November, we plan to file a rate case in Minnesota. The rate case is driven by capital investment and will incorporate key provisions of the legislation into the filing. While we won't discuss the specifics of the request prior to the filing, I do want to provide you with the overall framework of the case.

We are filing a three-year multi-year rate plan. We're also providing an option to extend that three-year plan to five years. In addition, we will be requesting interim rates for both 2016 and 2017.

While the case could take over a year to complete, we are going to see if we can settle the case or offer mediation to shorten the time frame to reach a final decision. I believe the combination of the legislation, the resource plan filing, stakeholder outreach and the optionality of the multi-year plan filing put us in excellent position to achieve a constructive outcome in the Minnesota rate case.

So now let me focus on investment opportunities. We had previously discussed our plans to step into the development of the Courtenay Wind project. During the quarter, we received approval from both the Minnesota and the North Dakota Commission.

As a result, we are moving forward with the project, which will now be included in rate base versus the PPA which was the original plan. This is an example of our steel for fuel strategy where we take a pass through cost, move it into rate base and cause a minimal if no impact to the customer bill.

Next, let me give you a quick update on our efforts to rate base natural gas reserves. In August and September, the Colorado Commission held informational meetings to examine the long-term supply of natural gas and approaches to managing prices including the rate basing of natural gas reserves. The meetings were very helpful and informative.

We plan to submit a regulatory filing before year end that will establish a formal framework and incorporates feedback from the meetings. Following the Commission's decision on a preferred framework, we anticipate filing for the approval of potential investments during the second half of 2016.

Finally, this week, SPS is filing to transfer about $100 million of transmission facilities located in Kansas and Oklahoma from SPS one of our Transcos. SPS no longer provides retail electric service in Kansas and Oklahoma. So this is a good opportunity to seed one of our Transcos with some assets.

SPS will make various regulatory filings at both the state and federal levels, and final approval is expected to take about a year. So you can see it has been an exciting and successful quarter.

I will now turn the call over to Teresa, who will provide more detail on our financial results and outlook in addition to our regulatory update. Teresa?

Thank you Ben, and good morning. Today we reported ongoing earnings for the third quarter of $0.84 per share, which compares with $0.73 per share last year.

The most significant drivers in the quarter were improved electric margin which increased earnings by $0.14 per share and was largely due to new rates and higher rider revenues driven by infrastructure investment that provide long-term value to our customers. The incremental revenue also reflects the impact of favorable weather. Offsetting the higher electric margin was increased depreciation, lower AFUDC earnings, higher property taxes and higher interest expense.

Turning to sales, our year-to-date weather normalized electric sales were down 0.2%, driven primarily by lower residential use per customer, partially offset by customer growth. We continue to experience healthy economies in our service territories, with an average unemployment rate of 3.6% compared to a national rate of 5.1%. Our customer additions remained solid at about 1%.

We have adjusted our electric sales assumption, and now we anticipate flat sales growth for 2015 reflecting our year-to-date results. We will continue to monitor sales and customer usage and will take appropriate management action if we determine this represents a longer-term trend. It is important to note that in 2016, we will be implementing decoupling for the residential and small C&I customer classes in Minnesota, which should address any declining customer usage trend.

Next I will provide an update on several regulatory proceedings. Additional details are included in our earnings release.

In Colorado, we have a pending natural gas rate case, and we are waiting for an ALJ recommendation, which we should receive shortly. The Commission is expected to rule in January 2016. As a reminder, interim rates were implemented in October.

In New Mexico, we refiled our electric rate case which seeks an increase of $45.4 million based on an ROE of 10.25%, and equity ratio of about 54%, and a historical test year adjusted for known and measurable changes. A Commission decision and implantation of final rates is anticipated in 2016.

Finally in our Texas electric rate case, in mid-October we received the ALJ recommendations, which reflected a $1 million rate increase and compares to our requested increase of $42 million. The ALJ's recommendation was based on a ROE of 9.7% and an equity ratio of almost 54%.

We reviewed the recommendations and believed there were errors in the filing and therefore sent a letter to notify the Texas Commission of our concerns. Late yesterday, the Texas staff revised the recommended rating increase to $14.4 million.

Please note that due to the timing of this update, our earnings release does not reflect this revised revenue recommendation. In addition, we have not had a chance to analyze this subsequent filing.

The ALJ's recommendations are somewhat mixed. We prevailed on a number of key items such as cost allocation issues that if supported by the Commission will establish solid precedents and should eliminate these disputes in future proceedings.

Unfortunately, the ALJ's recommendation did not vary from historic test year precedents and rejected our forward-looking adjustments for post test year planned additions and STP cost, which represented a significant portion of our request. We believe these adjustments relate to policy decisions about the best way to alleviate revelatory lag, which needs to be addressed by the Commission.

While the Commission isn't required to implement provisions of the recently passed legislation in this case, we remain hopeful that the Commission will be more open to addressing regulatory lag, taking into consideration the intent of the legislation in making its final decision in this case. The Commission is expected to rule by year-end with new rates effective by January 2016.

In our earnings release today, we also announced that we will start using market share purchase to fund our dividend reinvestment and benefit program in 2016. This will eliminate an annual equity issuance of about $75 million and reflects the continued strength of our balance sheet and projected cash flows.

This morning, we are narrowing our 2015 ongoing earnings guidance range to $2.05 to $2.15 per share. Previously the range was $2 to $2.15 per share.

We are also initiating our 2016 ongoing earnings guidance range of $2.12 to $2.27 per share, which is consistent with our objective of growing EPS 4% to 6% annually. Please note our guidance ranges are based on several key assumptions which are detailed in our earnings release.

I would also like to mention that we will be hosting an analyst meeting at the New York Stock Exchange on December 3. At the meeting, we plan to update you on our plans to achieve our 50 basis point improvement in earned ROE, our regulatory plan, our plans to meet the requirements of the EPA's Clean Power Plan, our five-year capital forecast including potential incremental investment opportunities. And finally, we will update our rate base growth estimates and financing plan.

With that, I will wrap up my comments. We had an excellent quarter and are on track to deliver 2015 ongoing earnings within our guidance range for the 11th consecutive year. We are on track to deliver O&M consistent with our zero to 2% objective.

We initiated 2016 earnings guidance which is in line with our 4% to 6% long-term earnings per share growth rate objective. We filed our revised resource plan in Minnesota, which is designed to reduce carbon on the NSP system by 60% by 2030.

We have received all regulatory approvals for the Courtenay Wind project. We completed the Commission informational meeting on the rate basing of natural gas reserves in Colorado. We've made progress on several revelatory dockets and intend to file our Minnesota multi-year rate case next week.

Finally, we eliminated all equity issuance is from our forecast beginning in 2016. Operator, with that, we will now take questions.

(Operator Instructions)

Ali Agha, SunTrust.

Thank you, good morning. On slide 10 where you give us your last 12-month ongoing ROE, which has the total OPCO at 9.02%, can you just remind us of what is the weighted average authorized to compare it to just to get a sense of how much lag there is on this last 12-month basis?

Ali, on average we utilize -- our proxy is about 9.8%.

9.8%, okay. And Teresa, also in the 2016 guidance, what is the embedded earned ROE that you budgeted there?

In terms of the regulated companies, it's just north of 9%. About 9.1%.

You're not assuming much improvement between 2015 and 2016?

Remember we have some weather embedded in 2015 and other things. So we have taken those out of our 2016 guidance.

Okay, because I thought year-to-date weather was a negative penny on your disclosures versus normal. I did not think is was a big factor.

It is a small factor, but we have taken that out.

I think what you're getting to is the 2018 goal of reducing lag by 50 basis points. We typically have 100 basis points of lag. We are going to make improvement in 2016.

We are very confident, clearly we have to execute on our revelatory plans and our cost control, but we are confident we are going to do that. And you should be confident that we're going to meet that goal by 2018 and we will show incremental improvement in 2016, 2017 and then meet it by 2018.

Ben, just to be clear, if through the September quarter you're at 9.02%, is that a good proxy of where you're going to end calendar 2015, as well, given that your big quarters are now behind you?

I'm not quite sure I can answer that question, Ali. I will tell you we narrow the guidance range, so you probably can do the math.

I think there is symmetry, as there is with 2016 guidance. So I think it's pretty transparent where we are going.

Okay. And then the lower growth trends, as we look at how the year-to-date numbers are going and we now are assuming flat to low growth this year, what is the visibility or confidence that you can move up to have 1% growth next year? What is changing? What do you expect to change to see that pick up?

First thing I would remind you, Ali, is that we have less sensitivity as far as earnings goes with the decoupling mechanism that we put in place starting in 2016 in Minnesota. So keep that in mind.

We are still seeing good customer growth, about 1%. So that is a good thing, particularly when you combine it with the decoupling mechanism. Teresa, I think the third quarter was a bit better?

It was better. The second quarter is where we actually saw the greatest decline this year, and so we actually were positive in terms of our electric growth in the third quarter.

Last question. Coming back to the gas reserve process, what's your sense, Ben? Do you think that the Commission will have formalized their plans by the end of the first half that would allow you to come in in the second half?

Recent meetings I've had with some of the Colorado commissioners suggest that they may take up to a year to figure out what their plan is, so by end of 2016, as opposed to earlier than that. Just curious what your thoughts are on when that is firmed up?

Well, it could take longer, Ali, but we're going to make our filing., And I think we certainly don't want to see market opportunities slip away.

And I think everyone realizes it's a pretty good time to do these investments. I think the compelling economic arguments will drive us to be able to be in a position to move forward as we have outlined.

Thank you.

Travis Miller, MorningStar.

Good morning, thank you. I was looking at slide 18 for a question here. The slide 18 where you have the ROE sensitivities, could you walk real quickly through which of those have the opportunity to realize those changes in the next year or two?

Obviously Minnesota electric, I would assume you have an ROE proposal there. What other jurisdictions there would have the opportunity to go plus or minus on that ROE?

Well, obviously Minnesota. In terms of Colorado, in terms of how we come out, we do have our three-year plan, so we will actively manage that. We have several rate cases that are proceeding or coming to closure, so there could be some opportunities with those, as well.

Okay, is there anything beyond 2016 or 2017 range where you think there could be opportunities there?

This is just a sensitivity graph and just showing you the impact of 100 basis points change. I think really if we -- as you know, we typically have been under earning 100 basis points. And if we -- we are still on the line, right Travis?

Yes.

Sorry, we just had a screen go blank here. So if we can't improve that position, we're going to be at the low end of our CAGR EPS growth rate.

If we achieve our goal, we're going to be in the middle to upper end. And if we can close that gap completely, and that's what I think this chart is trying to show you, then we would actually exceed our CAGR growth rates.

So what is going to be the big driver on that? Obviously Minnesota is going to drive a lot of it, and this five-year or three-year, or whatever we end up with is going to be a big driver in where we are.

But there is other places. Colorado we have been over earnings, so the multi-year plans have worked for both investor and consumer alike.

And then the unknown is Texas. We can continue to improve that regulatory compact, take advantage of the new legislation, continue to move the regulatory compact, combine that with the transmission riders we have, that will push it all up in the upper end.

It's getting better alignment with our regulators, combining that with cost control, we don't need to issue equity and that is great. I think we have a robust CapEx pipeline. I don't want you to get too caught up on this chart here, because that is really just to show you numerically what 100 basis points movement does.

Okay got it, thanks, that's helpful. Conceptually here with the Clean Power Plan and the resource plan in Minnesota, potential rate case over a three or five-year period, what are your thoughts generally on customer rate impact if you were to get to that type of goal, that 60% of clean energy type of level?

I've got to tell you, that is a great question. It's something that we really focus on because rate base growth is great, that's why we're focused on fuel for steel or steel for fuel, whichever way you like it. It's basically -- the good thing about it is it doesn't impact the customers very much.

So to specifically answer your question, obviously when you look at 2030 or through 2030, it's going to depend upon what set of assumptions you buy into. I think we are in an environment where gas prices are going to be pretty stable. I think we're in an environment where renewable is going to continue to fall even if they're not supported as robustly at the federal level with ITC and PTC.

But really when I look at it, I think that meeting -- exceeding the Clean Power Plans, reducing our missions by 60% here in the upper Midwest can be done over a cumulative 15-year period, but no more than perhaps a 2% cumulative increase over that time frame. So negligible right?

And so, the real issue is going to be can we build out infrastructure, can we do these other things and not have that pace exceed customer affordability. I think the answer to that is yes, we can.

Getting into multi-year compacts is they way you do that, cost control is the way you do that. Discipline about your capital investment is the way you do that. We are spending a lot of time on that, and I'm very confident this plan is going to be affordable.

Okay great, thanks so much. Appreciate the thoughts.

Travis, I'd just say, all you have to do is look at some of the wind assets and other assets we're bringing on there. They are right on parity with fossil, and I think they will be, too, even with the expiration of tax credits.

Okay great, thank you.

Chris Turnure, JPMorgan.

Morning. You recently increased your dividend growth guidance to 5% to 7%, and you established that payout target of 60% to 70%. I just wanted to get a sense -- going forward, you eliminated the drip in 2016 and beyond I guess. And in the event there is less opportunity to deploy your capital, how do you think about the trade-off between increasing the dividend more, upping the payout ratio to the higher end of the 60% to 70% range versus maybe buying back debt or deleveraging?

Let me just say it's nice to have a lot of options. That's what we've created for the investor, I believe.

I take a little bit of -- I will argue a little bit. I think we have a pretty robust capital forecast ahead of us, and I'm very optimistic beyond the five-year plan we will continue to have that pipeline as we implement Clean Power Plans and other things across all our service territory. And we will give you some more clarity on that at our analyst day.

Could we do more? Sure. And we're going to -- our stated goal is to grow the dividend at 5% to 7%.

We have a lot of runway, but right now that is what we are focused on. 4% to 6% EPS growth. 5% to 7% dividend growth. If we're at the upper end of our EPS growth rate, we will never really exceed that 60% -- the payout ratio today would stay about the same, which would give us more flexibility.

So it's really -- I think we're in a great position to have a lot of levers to reward shareholders. And one of the things everybody worries about is rising interest rates. And if and when that ever happens, it's great to be able to do more with your dividends to perhaps offset that risk, and we've got that flexibility.

Okay, great. And then I wanted to drill a little bit more into the situation in Texas right now. Teresa, you gave a bit of detail in your comments on your requests for a forward-looking test year, based on what the legislation had suggested or allowed for, but could you give us maybe more context here? I think it's difficult to understand the mandate or lack thereof on the Commission, and what recourse you would have, what kind of next steps you would have there if in fact the final decision said no on that.

Maybe we will start with it wasn't a forward test year in terms of what we had filed. It was basically a historical test year with known and measurable adjustments. So that was our baseline.

The ALJ's recommendation came back excluding those. We do think this is a policy decision and that that would be something that the Commission would make, not necessarily ALJ's would make.

As I indicated, we're hopeful that when the Commission actually rules on this, that they will take into consideration the new legislation that was passed earlier this year to include the post test year adjustments. Now, they wouldn't be required, but we are very hopeful, because it has been basically implemented with the new legislation.

I think Teresa's right. I mean, the ALJ probably would be more reluctant to make a policy call.

As you know, this is the last rate case we filed prior to that legislation. But the legislation exists, so you would like to think the Commission would look towards that as they review the case. But we're going to know by the end of the year.

Okay, and do you think the fact that the case was filed before the legislation was passed is a significant issue?

Clearly the legislation was not in place when we filed that case. That is a factor.

Okay. Great, thanks.

Travis, just be clear, this is the last case where essentially the Commissioner has discretion. On future cases, the decision will be based on the legislation that was passed.

Michael Weinstein, UBS.

Hello, good morning.

I was curious about if the Minnesota -- the next rate case is going to be multi-year and the Clean Power Plan portion of the IRP is going to be during that, probably some of the construction would be occurring during that period, during a plan that has already been filed and in place. Is there any -- can we expect to see some of the construction that is in the IRP before the IRP is approved within the upcoming rate filing in Minnesota?

Maybe I will start with that and then Ben, you can jump in. The things in terms of additional construction potentially in particularly ownership, we do have renewable riders available for an infrastructure investment. So we would think it would be not part of that base rate case plan, if that helps explain in terms of how this could play out.

Also, sorry if I missed this before, but have you -- have you had any indication so far from other parties about what kind of length of a plan that might accessible?

Are you talking about now in Minnesota with the three-year plan we filed with the option to go five?

Was there a lot of opposition to five? I'm just curious what that climate is.

I think anytime you do something new, you're going to get some resistance. That is just the way things go.

But I have to tell you, I think -- I had the opportunity to talk to the Commission as I made in my opening remarks, and I think they were pretty interested in learning about it. I think everyone knows we should be looking at more efficient ways to process the recovery of our infrastructure investment, and I think there is compelling reasons to go to five years.

That said, if it's three years, it's three years. The key is to have the longest runway possible and to close the regulatory gap and -- really one of the things, too, is that I really want to have more dialogs with all stakeholders and certainly policy makers and regulators about the kinds of opportunities and the things we need to do to advance the ball here in Minnesota. That goes for all our jurisdictions, as well.

What do you think is the key portion of regulatory lag that you're experiencing that you expect to reduce by 50 bps by 2018?

I think it depends. Minnesota is the biggest place. That is where most of the -- it's the biggest jurisdiction that has some lag.

A lot of that has to do with the fact that we filed -- we broke ground with the multi-year plan in this last rate case, but it wasn't a comprehensive multi-year plan. We didn't get -- we were able to step in to large capital projects in that second year, but that meant all the traditional projects, we had to wait. So that creates lag on that.

We have had some property tax increases. We have had forecast for sales that did not quite live up to expectations in Minnesota.

So a lot of that -- sales is taken through with the decoupling mechanism, and the other pieces will pick up in this more comprehensive multi-year plan that we now have available to us via the legislation. I would say that's the biggest thing, wouldn't you Teresa?

No, I would agree. And some of the lag historically has been tied to specific issues, and Ben was mentioning that property taxes that Monticello, in terms of some exclusions of the investments, that is behind us now.

In terms of resolving that issue, even going back a couple of years, the Sherco catastrophic incident, that caused some lag, as well. But those big issues we think are behind us, and as Ben indicated, this will be a comprehensive filing that we think will well position us.

And just to build on what Teresa said, this is a case that is very straightforward. It's recovery of capital investments. So it's a capital base case.

There is very little O&M in this filing. And one of the things we wanted to do is bring down our operating expenses, and we are accomplishing that.

Would it be safe to say the you're being conservative when you project a 9.1% for next year ROE?

I'm not quite sure -- I wouldn't get fixated on that number. I think we're going to be --our guidance is symmetrical, so you can -- we have as much upside as downside to be in the middle of the range. We're to make improve in 2016, and then it's going to be steady improvement.

How much, and what we can accomplish in 2016 is going to -- Minnesota's going to move the needle, obviously, and what happens there, but there's other jurisdictions as well. I think we're in really good shape to achieve our reduction of 50 basis points lag by 2018.

All right, thank you very much.

Thank you.

Paul Ridzon, KeyBanc.

Good morning. Maybe it's early in the process, but have you quantified what your annual -- how much you'd like to rate base in Colorado for natural gas?

We've never really quantified it, and we're going to start relatively small and build on that. But if we just look at the LDC requirements in Colorado and if you assume we did about 25% of that through natural gas reserves and rate base, I think over a decade, you're probably looking at about $500 million, could be more. And obviously you could do more than 25%, and you could obviously expand that beyond just the LDC requirements in Colorado.

Do you think you would do it chunky, or do the same size annually?

I don't think you want to do it all at once. But I think there's probably logistical things you would have to consider. I don't think it would just be I think it would be semi chunky. How is that (laughter)?

Obviously just depends on the asset opportunities and how big they are.

That is better said.

Thank you very much.

You're welcome.

Paul Patterson, Glenrock Associates.

Good morning. A couple of things.

You told a pretty compelling story up for the multi-year plan and what have you in Minnesota. I'm just wondering if it were not to happen, are there other levers that you are contemplating for perhaps closing the ROE lag or potential ROE lag going forward?

We are obviously going to do everything we can to achieve our earnings goals. So we'd have to see -- I'm pretty confident we're going to be able to get a multi-year plan in place. I would rather it be five, it could be three. And I think there's a lot of openness to that.

I think we're getting into really hypothetical situations. We'd have to react to whatever the Commission, as we always do, gave us.

The point is we would have to be probably more disciplined on the cost side, but you start to get -- you can achieve earnings goals, but at some point I think they cut into some of your other objectives with building out the infrastructure, modernizing it, giving customers better options, achieving environmental excellence, al those things that are the hallmark of a Xcel Energy. I don't think that's a bridge we're going to have to cross, Paul.

I would agree with you. Frankly we've already completed one multi-year plan. So we have the precedent behind us, and we have the new legislation.

So that seems like minimal risk that we would not be able to complete a multi-year. It's just how many years.

Okay. Then the second question, and I apologize -- I just didn't get this completely. You guys mentioned I think transferring assets -- transmission of assets from SPS to a Transco. Could you elaborate a little more on that in terms of the size of the assets?

These are assets that are in Kansas and Oklahoma where we no longer serve retail load there. You may recall we sold those jurisdictions off a few years ago. So we think it's an opportune time to move those assets, and specifically they are worth about $100 million, into one of our Transcos and seed those Transcos with some assets.

And maybe just to supplement that, it is about 230 miles of transmission line. It is 345-kV, and it's the line plus additional equipment that goes with the line.

It sounds pretty small. For the purpose of this, obviously you might prefer Transcos. Like you said, it's seeded, so therefore you could expand on it you think in a more effective way? Grow it or something in a more effective way then where it currently is?

While it's small, but I bet you a lot of other people would love to have that opportunity, as everybody competes for it. I think there is some value too to have actual assets inside of Transco. I think it gives you more gravitas, if you will, when we get into the FERC 1000 bidding process.

It would help in terms of establishing the public utility status in Kansas for the Transco. So there's several benefits of feeding it.

I guess, stay tuned on that. And then on wind versus fossil, I think without the tax benefit you think it will be competitive. Could you just elaborate a little bit more on that, or quantify that slightly to me in terms of how competitive you're seeing that in terms of fossil?

Well let's start with what we have today, and I will stick with wind, which does enjoy the production tax credit, which is worth about $22 a megawatt hour. With that credit in mind, we're seeing wind deals that have come to us across all of our regions in the mid-[$]20s megawatt hour, levelized, 20 years.

Now compare that, Paul, to what we could go out today and buy a strip of natural gas future contracts for. Even in this low gas price environment, if you took those gas reserves, times it by the applicable heat rate, I think you'd find $25 a megawatt hour for wind would be on parity if not in the money.

So essentially what we're doing, why we are buying wind is hedging natural gas volatility. Obviously if you take away $22 from the equation, you're not looking at $25, you're looking at $47. It's a little bit out of the money. Of course, natural gas prices are at historic lows.

And then I would say, and this implies the solar as well, is that they continue these technology at large-scale to become more and more efficient. So I don't think their pricing is going to go up.

I think wind if anything will stay flat, but we've seen -- in just five years, we've seen capacity factors go from the mid-[30s] and to now the low [50s]. They have seen steady improvements, we all know the story with solar. So I'm optimistic about it.

Okay. I mean, I guess we're just looking at pure megawatt hour. We're not talking about the benefit of dispatch or anything like that. You're just saying if you look at it from a pure megawatt hour perspective and technology, you're thinking you can get somewhere close to that.

Paul, that is a good question, and I'd be happy to talk to you more about it, because I was just looking at -- I used wind as an example because I think it's easy to get your arms around. Wind today -- you still build a gas plant, but whether you fire up the gas plant with natural gas or you idle it and have it ready to go but you displace the natural gas with wind is the equation I was talking to you about.

It gets a little more complicated when we talk about solar, and the way I look at it, briefly, is probably the capacity value that you bake into that is the difference between a combined cycle plant and a combustion turbine plant roughly. It gets a little more complicated, and we can probably take it off-line, but it's pretty exciting economics.

And then you get the ancillary costs as you get more on the system. It's one of the reasons why were studying more and more what batteries can do for us.

It's not like batteries are in the money for us today, but neither was solar 10 years ago. And so we want to be ready for when the technology moves into the value part of our sweet spot.

Great, makes sense, thanks a lot.

Andy Levi, Avon Capital Advisors.

Hi, good morning. I think I'm all set, but maybe just a couple housekeeping stuff. Just on the stock issuance of or lack of it, even the drip is eliminated, so the shares should stay where they are for the next couple of years? There would be no increase in the shares at all, or some type of employee plans --?

That is correct, Andy.

Okay good, I had a couple million per year. And, I think it's called the Courtenay Wind Farm, is that correct? What is the status of that?

All approvals have been received, and we're in the construction mode. It's going very well.

And that will come online the end of 2016.

Yes, towards the end of 2016, a little before the end of 2016.

Is anything in your 2016 forecast for Courtenay?

We haven't updated our CapEx for Courtney, and that will be one of the things we update for you on our analyst day.

Okay, but that would really be -- that would be 2017 earnings or you would get some AFUDC from that? Isn't there some type of rider in Minnesota, something like that?

There is a rider mechanism.

Right, so I guess -- I understand you did not update the CapEx, but is that incorporated in your forecast that you gave for 2016 or not?

That part of it is all embedded in that overall 2016 guidance number we gave you.

Okay. That's great. And then just one last question on the gas reserves.

Just to understand, you wouldn't strike a deal with a farmer, for no better way to put it, without regulatory approval. Is that correct or would you go to the regulators even though the scheme itself is not finalized?

We would not get ahead of ourselves if that's what you mean. Not quite sure what your question is.

You get the framework established, Andy, and then the specific way you implement that, I think if it's in the framework, you give yourself leeway so you don't have to run back and have this endless clock running. That's what we're trying establish now is how you would execute on it and what the model would look like.

Right, but the framework is not set yet. Is that correct?

Correct.

We're going to file before the end of the year the framework.

Okay, got it.

But we love doing deals with farmers (laughter).

And I will leave that alone. I will not talk about those new Colorado performers.

(laughter) Hey, that's good load, Andy.

Half a percent I heard of growth, isn't it? Seriously, isn't it something like that?

It's not insignificant.

Okay, thank you very much.

Anthony Crowdell, Jefferies.

Good morning, just a question -- it looks like the Street and most of us are expecting the Company to narrow the earnings gap from 100 to 50 basis points. You've been very clear that you hope to get there by 2018. But if I thought longer-term, do you think there is an ability to narrow that gap even more to maybe earning your allowed return in all your businesses?

That is the goal. So yes, the answer is yes.

Is it an attainable goal, or is it structural that it's hard to do with large CapEx spend or --?

It's not a vision that can't be achieved. It's aspirational I guess you would say, but it's not pie in the sky by any means. Look at what we've already done in Colorado in the multi-year plan. Look at what we're doing in Wisconsin.

I hope to be able to report really positive sorts results for you in Minnesota. Texas, that is probably going to be harder when you're in historic mode and building a lot of capital, but at some point, that capital profile slows down a bit and so the lag becomes less pronounced. I think it's not impossible at all.

I think that's why we're so focused on multi-year plans, the tenants have multi-year plans because it provides flexibility that could allow opportunity to earn a greater return.

Cost control, sales, all that would enter into it at that point.

As you're introducing multi-year plans in Minnesota, I think Ben, you had said you met with some of the regulators or whatever and they were very interested in the multi-year plan. What would be the opposition to a multi-year plan for the regulators?

Change. That's probably the one word I would use.

I think the multi-year plan, to supplement that, because we are using forecasts and potentially would there be a question of over earnings, and I think we can put things in place to moderate that if we get -- in that event.

There's change, and then you can have still bullet points under it. But the reality is it's different from the way we've done it before.

And in Minnesota, there's always the ability if the regulator believes you're over earning in a long-term plan to call you back in. Is that correct?

Every jurisdiction has that ability.

That's right.

So perfect. Thanks so much for taking my question.

We appreciate it, thank you.

With no further questions left in the phone queue, I would like to turn the conference back over to Teresa Madden for any additional or closing remarks.

Thank you all for participating in our earnings call this morning. Please contact Paul Johnson and the IR team with any follow-up questions, and we look forward to seeing you at EEI.

Thanks everyone.

Thanks.

And this does conclude today's presentation. We thank everyone for their participation.