Good day, ladies and gentlemen, and welcome to the Black Hills Corporation Fourth Quarter and Full Year 2016 Earnings Conference Call. My name is Liz and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Following the prepared remarks, there will be a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to Mr. Dave Soderquist, Investor Relations Analyst of Black Hills Corporation. Please proceed, sir.

Thank you, Liz. Good morning, everyone and welcome to Black Hills Corporation’s fourth quarter and full year 2016 earnings conference call. Our materials for the fourth quarter and full year 2016, including our earnings release and webcast presentation can be found on our Web site at www.blackhillscorp.com. Leading our earnings discussion today are David Emery, Chairman and Chief Executive Officer; and Rich Kinzley, Senior Vice President and Chief Financial Officer. During our earnings discussion today, some of the comments we make may contain forward-looking statements as defined by the Securities and Exchange Commission, and there are a number of uncertainties inherent in such comments. Although we believe that our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. We direct you to our earnings release, Slide 2 of the investor presentation on our Web site, and our most recent Form 10-K, Form 10-Q and other documents filed with the Securities and Exchange Commission, for a list of some of the factors that could cause future results to differ materially from our expectations. I will now turn the call over to David Emery.

All right. Thank you, Dave. Good morning, everyone. For those of you following along on the webcast presentation deck, I will be starting on Slide 3. This morning we will follow a similar format that we followed in previous quarters. I will give a quick update on the quarter, our CFO, Rich Kinzley, will provide some financial updates related to the quarter and year end and then I will talk about forward strategy and then after that we will take questions. So moving on to Slide 5. We had a great fourth quarter. It really capped off an excellent 2016. During the quarter we completed two key strategic power generation projects. We essentially completed the integration of our SourceGas acquisition and posted strong quarterly earnings results. On the utilities side, several highlights for the quarter. Our Colorado Electric utility finalized the purchase of $109 million, 60-megawatt Peak View Wind project. We also completed the $63 million, 40-megawatt natural gas fired turbine at our Pueblo Airport Generation Station. Related to that turbine, you may recall on May 3 we filed a request with the Colorado PUC to increase annual revenues $8.5 million. On December 16 the PUC granted $1.2 million of new revenue beginning in 2017, and that’s in addition to the $5.9 million in recurring annual revenue from our construction financing rider which had been previously approved by the PUC. We were very disappointed in the PUC's decision. It was contrary to both state law and prior Colorado PUC precedent and we also believe that Commissioner Koncilja acted with bias during the proceeding. So on January 17 we filed for reconsideration of the decision and also filed to recuse Commissioner Koncilja from the proceeding. Also during the fourth quarter our South Dakota Electric utility continued construction on our $54 million…

Great. Thanks, Dave and good morning, everyone. As Dave noted, we have completed the heavy lifting around integrating the SourceGas utilities and we are proud to celebrate our performance in 2016. In addition to the substantial growth in our gas utilities from the SourceGas acquisition, we are pleased to report another year of strong operating performance at our other core business segments. On Slide 11, we reconcile GAAP earnings to earnings as adjusted, a non-GAAP measure. We do this to isolate special items and communicate earnings that we believe better represent our ongoing performance. This Slide illustrates our strong earnings growth for both the quarter and for the full year. For the fourth quarter in particular, earnings for 2016 were far in excess of 2015, thanks largely to the earning contribution from the acquired SourceGas utilities during the winter heating season. Specifically, as adjusted EPS for the fourth quarter was $1.07 per share compared to $0.71 per share in the fourth quarter last year. As I have mentioned on prior calls, we have a seasonal earnings stream with the greatest level of earnings in the first and fourth quarters. As adjusted EPS grew for the full year 2016 to $3.19 from $2.98 in 2015, representing 7% year-over-year growth. As detailed on this Slide, we experienced special items not reflective of our ongoing performance in each quarter of 2016 and in 2015. The first is non-cash impairments at our oil and gas business due to continued low commodity prices. The second is acquisition related expenses such as advisory fees financing and other third party cost associated with the SourceGas acquisition and integration. While we may have continued integration cost in 2017, we expect them to be minimal given the substantial completion of most major integration activities in 2016. Slide 12 displays…

All right. Thank you, Rich. Moving on to Slide 25. We group our long-term strategic goals in to four major categories with the overall objective of being an industry leader in all we do. On Slide 26, as discussed in a little more detail on the third quarter call, we have a tremendous opportunity to provide earnings growth by improving the efficiency and reducing the cost of the combined Black Hills and SourceGas company while we focus our capital spending to reduce or eliminate regulatory lag to the extent possible. Slide 27. A strong capital spending has and will continue to drive our earnings growth even with an increased focus on reducing regulatory lag, we still expect to spend about $1 billion from 2017 to 2019, continuing to spend far in excess of depreciation. Slide 28 provides more detail on our recently completed Pueblo Airport Generating Station 40 megawatt turbine. That project was placed in service on schedule and slightly under budget on December 29. Moving on to Slide 29. Also as noted earlier, our $109 million Peak View Wind project was placed in service on early November, nearly two months ahead of schedule. It will help us comply with Colorado's renewable energy standard. Slide 30. In the last several week we have made significant progress on our Colorado electric resource plan. We entered into a settlement agreement specifying the addition of approximately 60 megawatts of renewable energy to be in service by 2019. That will help us continue to comply with the renewable energy standard in the state of Colorado. On January 17, Colorado administrative law judge issued an order approving this settlement agreement that will become effective as of February 6. We now intend to issue an RFP seeking proposals for 60 megawatts of renewable energy. Hopefully, later…

[Operator Instructions] Your first question comes from Michael Weinstein with Credit Suisse.

First question is about the settlement in Colorado for the IRP. Can you discuss some of the terms around that, especially around cost recovery and the discussions perhaps with the governor's office or any other discussions you had that led to that settlement.

Well, the settlement was just part of kind of an ongoing process there. You know we approached this one very similar to the way we approached our Peak View project. There is no specification on specifically which resources will be implemented and whether those will be company-owned or whether those will be third party resources. So the specifics of that really won't occur until after we go out, issue the RFP, get the results, analyze the results. Then we will go back to the commission with a specific recommendation for the resources that we intend to utilize, that we recommend utilizing. If those are company-owned, obviously that will have implication related to how the costs are going to recovered there. If they are just simply power purchase agreements, obviously that will be different. But the commission then will have to approve the resulting resource at that time.

Right. I guess, what I am asking is, in reference to the way the Pueblo Airport Generating Station was treated. And recently I know that you may be concerned about cost recovery in the state and I am wondering if this settlement does anything to alleviate any concerns over that.

Yes. I don’t think the settlement really addresses anything related to cost recovery. Obviously we are concerned about cost recovery. I mentioned our disappointment in the rate case related to the turbine. That being said, if you look at the Peak View Wind project, that was recovered including our return through a series of riders. That was a reasonable mechanism with which to make a good return on that investment. We are cautious about making additional investments in the state. We are anxious to see how the commission now moves forward with two new members. And we will be watching that as we analyze the RFP results in making the decision whether or not we want to invest additional capital there. We certainly would like to and we hope that we can get comfortable with doing so.

Right. And I was wondering if you could just provide, I guess more certainty and clarity around what might happen if, as an alternative to cost of service gas with the remaining E&P assets, what are your thoughts for 2018 and beyond.

Yes. You know the timing is going to be the issue there, Mike. I think we have been relatively clear that we don’t intend to stay in what I would call the traditional E&P business. As we have continued to migrate the corporation more and more towards being utility driven, which from our perspective we have said we have largely completed that journey, we believe we have got some expertise and some properties in E&P that would be extremely good assets to serve customer gas needs for years to come. Very cost effective assets. If we go through the process and the various commissions disagree with that, then we will have a decision to make on what to do with those E&P assets. I don’t think we intend to revisit our decision on the E&P business. You know we have kind of made the decision strategically that we are phasing out of the traditional E&P investment methodology and really looking to move on to something else that integrates vertically with our utilities. So if it's not successful, obviously we have a choice to make on the best way to continue to transition out of the E&P. But I don’t think it would change our decision that might just effect timing and the way we go about it.

Your next question comes from Chris Ellinghaus with Williams Capital.

Can you give us any other color on have you learned anything going through the cost of service gas process at this point? Do you feel better, worse? Can you just give us a little thought on where you think you are?

Yes. I would say we did learn something. It's an interesting process. Before we filed for approval last time we had 30 plus meetings with various regulators, commission staff, consumer advocates and everything else to really map out the strategy we took last time. And several of those folks suggested that it would be better for us to pursue that in two pieces. The first approval basically is setting the regulatory construct for the program. The rules of the road, if you will. And then the second approval phase being brining in a specific property. In reality what happened when we filed for that, it was very difficult for the staffs to get their arms around making a recommendation without specific numbers. And that’s really where we kind of got side tracked the first time. We did answer a thousand plus discovery questions in the various states. I think we learned a lot about what questions and concerns that the staffs and consumer advocates had related to a cost of service gas program. And that’s certainly helping us as we rethink how we would reapply. Certainly I don’t think we would reapply without including a specific property. I think that’s going to be necessary for them to really get their arms around true customer impact. And then the other thing, I think you know going through the process we have learned that it's probably really important to make sure they understand what the program is. And that is we are recommending that cost of service gas be part of a gas procurement portfolio for customers. We sincerely believe that over the long term it will provide significant benefits to customers. So we are making sure that we have a good plan in place. Making sure that when we do propose the program again, assuming we do that, that we have addressed the majority of the concerns that were expressed in the first round and provide specificity, if you will, that I think the staffs need in order to recommend the program to the commission.

Okay. Great. In the Colorado reconsideration of the turbine case. Is recusal a pretty rare instance and who decides if that is appropriate?

Yes. It's not terribly common, obviously. And we just felt like it was absolutely necessary to ask for it. We did not feel that we were getting a fair shake in any way, shape or form, unfortunately, and felt like we really had no other choice. It's not something we really preferred to do. In fact we would have avoided it at all costs pretty much but just felt like we didn’t have any choice. The process is -- and I don’t know the exact dates, but the commissioner has the ability to voluntarily recuse herself. If she does not, we could ask the other commissioners to do that and vote to do that instead. We would just have to play out that timeframe. That will unfold here in the next week to two weeks, I believe, Chris.

Okay. Maybe this is for Rich, but can you give us some thoughts on what you are thinking about in terms of new Trump policy and did you include any consideration of, say, tax reform or infrastructure in guidance.

No. We have not made any considerations of that at this point. We are certainly plugged in, Chris, to industry groups in evaluating different scenarios but at this point it's too early until we get more specificity around what the administration is going to do.

Your next question comes from Chris Turnure with JPMorgan.

Dave, I think in your prepared remarks and then in response to one of the questions, you indicated one potential scenario would be that you would not file at all for cost of service gas. Is that kind of something that’s amid the options here and if so, when would a sale process begin if that was the case.

Yes. You know it's certainly an option until we file. I would say we don’t preclude any options. I would say it's a somewhat unlikely one. We believe strongly in the program, we would like to file. We want to make sure that we have something that looks good to regulators and staff and we are working on how best to package that up now and how to really make good sense for customers, which we believe we can do. So I would say while it's a possibility, it's somewhat an unlikely one.

Okay. And then switching to tax reform. I know this is a difficult question to answer but how kind of likely do you think it is in the context of the law in various states and the regulatory constructs that you would actually get called in in the event of tax reform actually getting passed at the federal level, where those call-ins would involve just more than resetting the tax rate alone and in some way your settlements following SourceGas would be vulnerable here.

Yes, as you said, it's a very difficult question to answer, Chris. It depends on what the tax reform looks like, right. And there has been a lot of discussion about deductibility of interest and expensing of capital in different things. The way those would be handled might have an impact on how urgent the commission would be in wanting to call us in and whether in the normalization roles of course associated with how that happened, would impact I guess the sense of urgency on the part of the commissions on whether they really feel like they need to call us right away or not. It's been 30 years since this has happened. The last time you saw quite a few proceedings where companies were called in for rate reviews. Some of those were related really only to dealing with the tax reform, some were full blown rate cases. It's really difficult to speculate what we think what happened there until we know what the tax reform actually looks like. And you know, as Rich said, we are engaged with EEI and AGA and others, U.S. Chamber and others, on what the tax reform is going to look like and we will continue to stay very engaged in that. Obviously, we know what would be good for customers and what would not but until we see some more details out of Washington, it's very difficult to guess what's going to happen.

Okay. That’s helpful. And I would assume at this point you haven't had any conversations directly with the regulators on this point. It would be probably too soon to have done that.

Yes. No, we have not. You know in an ideal world if there was a major tax reform, we would hope we could confine the regulatory process dealing with the tax changes and not full blown rate cases in every jurisdictions but we really have no idea what's going to happen.

Your next question comes from Insoo Kim with RBC Capital Markets.

On the 2017 guidance, the 355 midpoint, do you guys embed any more type of one timers like tax benefits or anything there, I think for the year. Or could we look at the 355 as kind of a new base level to forecast future earnings growth power.

Yes. I think it's pretty fair to look at that as a new kind of baseline, Insoo. There is nothing material like what you suggested in there.

Understood. And then with the recent 6% dividend increase which was definitely higher than your previous years increases. The '17 payout is about 50% based on the midpoint of the guidance. Could you give a little more color on the timing of doing the 6% increase and what that tells about your earnings power going forward and where you ultimately want the payout ratio to be in relation to that?

We talk about a 50% to 60% payout ratio, we are going to continue to target that. Obviously, we are at the low end of that. I think we are balancing, Insoo, we are confident in our earnings growth capabilities, we talk about that. But in the near term we are balancing, delevering the balance sheet, earnings growth opportunities, CapEx opportunities and then the dividend growth. So it's just that balancing act. Our 47 year track record is very important to us and it's something we want to continue and I mentioned this earlier, we do take a cautious measured approach to how we look at dividend increases. We want to be comfortable that we can continue to increase dividends at a reasonable rate. That being said, we did increase it a little larger this year and I think a lot of that is, one, to get towards the bottom end of our targeted payout ratio, but two, is really in recognition of the continued change in the complexion of the company. The addition of a large section of essentially gas LDC businesses which are very low risk and strong cash flow businesses, improves our ability to continue to pay dividend and gave us more confidence to go off a larger than normal increase this year.

Understood. And then finally, I know you guys talked about the SourceGas acquisition not just having integration synergies but trying to realize operational synergies that you could have achieved among the gas utilities. The past few months have you found additional opportunities like that, and I am not sure if you are able to quantify this thing in relation to those synergies.

Yes. We are not able to quantify them but we have teams working on a lot of things. You know just to give you kind of a flavor for what those are, we have purchased numerous utilities over the years. And we have made a big deal about how quickly we integrate those on the consistent platforms, software, hardware, etcetera. There is still a lot of different day to day practices being conducted out in our various field operations. So one of the things we are doing is we have a got a group of teams working on specific issues. For example, how do you hook up a new customer. What are the specific steps that a field technician takes in both our gas utilities and our electric utilities, to the extent we can streamline that. Make it more efficient. Everyone uses the same process, it's going to make all of our technicians more efficient. We have also continued to automate the whole process through what we call our click iPad field technology. That’s part of the process as well as continuing to refine the software and the steps associated with the actual physical steps that are taking in the field. So that’s one example but we have quite a few that we are looking at. We haven't reached the point where we would quantify those yet, and maybe not talk a lot specifically about individual projects, but I think where you are really going to see it in is in our overall O&M and earnings numbers going forward. Our goal is to continue to push through those as quickly as we can. One of the things we saw, if you go all the way back to 2008, with our Aquila acquisition. After we got everyone unified on common software platforms, we saw a couple year period where we continued to get more and more efficient in our operations. Whether that was at the corporate level or at the field level. We know we have the ability to do that again, maybe even do a greater extent than we did with Aquila. There difference here is that you know we are pushing to make it happen rather than let it happen, if you will. We have proven to ourselves we can do it, so let's do it more quickly. So that’s what we are doing right now.

Your next question comes from Brian Chin with Bank of America Merrill Lynch.

I noticed in your prepared remarks you didn’t talk about, the idea about third party coming in on your gas reserve side. Was there any change in intent or though behind that?

No, it's still an idea that we like. We would love to do that. We have been talking to a couple of different parties, continue to talk to some. In an ideal world we would have a partner to participate with us, a utility partner to participate with us in the cost of service gas program. That’s certainly an avenue that we are pursuing and that really hasn’t changed.

The last time that you talked about this with all of us at EEI on the third quarter call, the thought was maybe we might have something around year-end or by this call. Has the time table shifted in your thought process or has something happened that caused the time table to move on?

Yes. I don’t think it's shifted much. You know what I would say is that if you are working with a partner, we want to allow sufficient time for that relationship to come together. And hopefully that can happen sometime here in the future. And then obviously, how we go about presenting our case to the regulators and which specific states that we want to file in. We are still working on that and still doing some analysis on basically how to present this in a way that staffs and regulators can get their arms around in a process that they are used to, if you will. So I would say nothing has really changed there. The time table is a little slower when you entertain a partner then it is when you go at it alone. But we definitely feel like if that take extra time, it's more than worth it.

Got you. And then one more from me. You know you guys were really clear in your prepared remarks about things that are coming up this year that might affect sort of the quarterly allocation of earnings versus last year. Assuming that we all do our job and parse through the transcripts properly, do you think that outside of those specific items you mentioned, are there any other quarterly allocation of earning issues that we should be thinking about that could differ from last year. Or should we use last year's quarterly allocations as a template for everything about the quarters this year around, just to avoid any issues around that this year.

I think if you kind of comb through not just only this transcript but prior quarters, it's going to get you directionally going where you need to, Brian. One thing that will change next year is more cost, you know the corporate segment had a pretty big loss this year because a lot of internal labor was allocated towards the integration effort and charged to corporate, and not broken out in the external acquisition expenses that we broke out. Those will next year generally be reallocated to all the business units. So that’s maybe the one tweak.

Well, and then the first quarter obviously is going to look a lot different. You have got a six-week difference in ownership there where we missed the first six weeks of the earnings, the prime earnings season in the gas utility. The January and like February. So that will definitely be different as well.

Your next question comes from Michael Worms with BMO Capital Markets.

Rich, you mentioned that there won't be as much at the market equity this year as opposed to last year. Can you kind of give us a little bit more color on that?

Yes. Our intent is to keep the program active, Mike, but certainly very minimal issuances this year. I mean unless something comes up where we need to be more aggressive with that, it's going to be quite minimal.

Okay. Fair enough. And then just another question unfortunately on the oil and gas business, but do you, I guess this is for Dave, do you need a partner before you decide to re-file for cost of service gas or would you consider going it alone?

You know, I don’t think we need one. I think it would be very beneficial to have one. One of the assets obviously that we are considering using for cost of service gas is our Piceance Basin property. When you do an affiliate transaction in a regulated utility model, that transaction is always subject to a pretty high degree of scrutiny. To the extent you have a third party in there with an arm's length negotiated transaction related to the same property, it really helps that situation. So I don’t think we have to have a partner and we would love to have one. I think it does a couple of things. It addresses the arms length issue but it also allows us to increase the size of the program and you get some economies of scale from drilling costs and service costs and other things like that by having a larger program, a larger drilling program than you would otherwise have, if you went at it alone.

Okay. Fair enough. And then just on the Colorado reconsideration case. You talked about, knowing about in the next week or two. Is that what the commission will do about the reconsideration or is that just specifically related to your request to have the commissioner recuse herself from the case.

Really both. You know both unfold in pretty quick timeline here in the next few weeks. The commissioner recusal issue comes first and then the actual triple R request for re-hearing, reconsideration. That’s next. And it's got a fairly short time fuse. By the end of February we will be through that process. We will see what we end up with for a result there. If we are not comfortable with that result that’s consistent with state law, namely the Colorado Clean Air Clean Jobs Act, we would likely appeal to the court system after that. We are hopeful that going through the commission process, particularly with a couple of new commissioners here that we will reach a reasonable outcome that’s consistent with state law and prior commission precedent.

Your next question comes from Andy Levi with Avon Capital Advisors.

Just on, I guess because we didn’t talk about in detail and I don’t know if you guys have prepared to yet, but on tax reform. Is there any type of, kind of high level beyond, obviously, we don’t know what the rules are, but whether it's interest deductibility, lower tax rates. How that may affect some of the numbers, particularly at the parent?

Yes. We are looking at all those things, Andy. We are looking at different scenarios, like I said earlier. But until we get more specifics about what the rules are, we don’t want to speculate what the impact is going to be.

How much parent debt do you guys have once the convert, so kind of back that out if that converts next year.

The vast majority of our debt is parent debt. We have got about $500 million of debt down at the operating company level.

Okay. So once you get through that convert, you are saying there is only $500 million of debt that’s at the parent level that’s not allocated to the utilities.

Well, at that parent that’s going to be about $2.9 billion.

Okay. 2.9, okay. What's the average interest rate on that?

I can't answer that off the top of my head, Andy. I would have to go look. I think our all-in weighted average rate of interest right now is about a little over 4%, 4 and a quarter-ish.

Right. And then do you benefit from any type of repair tax deductions or anything like that?

Yes, we do.

Okay. Can you quantify that?

No. Not off the top of my head.

Okay. And then the 11% tax rate that you had for 2016, what would be the normalized tax rate since I guess the 11%, part of that was so low because of certain right downs and things like that.

Well, again, in the first quarter we had almost $11 million of tax we settled with the IRS on an old outstanding issue for tax year 2007 through 2009. That was over $5 million. We changed the method by which we do depletion deductions at our oil and gas subsidiary and recognize benefits from the years 2007 through 2014 of almost $6 million on that. And then in the fourth quarter I detailed the few items there. So when you add all that up, it really tends to be the effective rate knocked at way down below what it normally would be.

So for '17, what you guys have embedded in the guidance as far as the tax rate?

We haven't disclosed the rate but it's going to be closer to what you would expect, kind of that 30% to 35% range.

Okay. More normalized rate. That’s good. Okay. And just back on the $2.9 billion, does that include the convert or not?

That would be after the convert converts.

After the convert converts. Okay. Great. Thank you very much.

[Operator Instructions] Your next question comes from Jim Marrone with Singular Research.

Just looking at the guidance with the comments of no significant acquisitions or divestitures. If there is an attractive asset and it's maybe like just a small asset and they have got a really attractive valuation, would you put that on the table, perhaps give it any consideration?

Of course. Yes. We are always looking. You know the issue right now is just given our balance sheet, it would be hard of us to lever up enough to be competitive on a large scale acquisition that had a lot of interest from other parties. But if we were to find a little tuck-in acquisition in some place where it really made great sense for us, we wouldn’t have any problems doing that. As Rich mentioned, we have got the ATM program, we have got some other things we could use to finance that. But big acquisitions, even though we might be interested and look right now, I think we would be fooling ourselves if we thought we could be as competitive as we were with SourceGas just because we just don’t have the leverage capacity that we did with that one. And we won't until 2018 and after the converts and all that. So while we are always looking for the right opportunity, certainly our competitiveness is going to be effected for any large ones in the next couple of years.

Your next question comes from Lasan Johong with Auvila Research.

David, if you bring in a partner for the development of the Mancos Shale for cost of gas service program. Does that mean that the actual production coming out of Mancos will accommodate both utilities as a desired level of, let's say 50% to 75% of the gas demand.

Yes. The Piceance has the capacity to provide a very large program, Lasan, with frankly resources to spare. So there is not an issue there. I think if we get a program up and running, the only question for the long-term is, do we want the entire program based on a single asset just from a market diversity of cost, and other perspectives. But that’s a problem that would occur multiple years down the road if we are successful in getting a program in place. But based on what we see for our needs and the potential parties that we have been talking to, the Piceance could easily supply those programs. I mean it's just whether you would want them to for the long term.

Staying on the subject, in the past when we talked about monetizing the oil and gas assets, Black Hills' preference was to develop the reserves and then sell it basically as a cash, about some cash for a future cash flow. If that's a take and you still have that kind of mentality, why not invest in Mancos now? Either way you are going to have to put money into it whether it goes to the cost of service gas program or whether you are going to sell it. If you are going to do either/or, you need to still develop it, why not put some money into it now while they are going good?

Well, I think the issue there, Lasan, is how much capital do you have to put in to prove the viability of the play. And the main...

If you [have] [ph] done that.

It's our view that we have put sufficient capital in there and done enough well testing and drilling, that we have a pretty good hand on forward economics. And so I think without cost of service gas, it doesn’t make sense for us to continue spending because we don’t need it to really value the property.

I got you. Do you have a preference for gas or electric utility acquisition next?

You know beggars can't be choosers, if you will. All right. I mean we like growing our utility businesses and you can't predict when something is going to become available or what's going to become available. We have said in the past that if you had a wish list, it would be an electric utility that needed power generation. Those few things are sweet spot for us. When you look at Cheyenne Light, you look at Colorado Electric, both were opportunities to buy electric utilities that were in desperate need of generation resources at a size that our folks are great at building and operating. So that in an ideal world, that would be the top of your wish list. You can't make those transactions happen that way and right now we have got a great mix. We are about 50:50 gas and electric assets, EBITDA etcetera. So we kind of like having that risk profile.

Okay. Last question. The PUC made a decision to $1.2 million for those renewable projects. That’s a 52.5 of your payout. How do they justify that? Is that basically saying, we don’t care about shareholders?

Yes. A couple of issues there, Lasan, and I think, and again not to dodge your question, but I think the best source of all the specifics and maybe you have read it already, is our request for the triple R has very good detail on what's happening there. But as I said in my prepared comments, we had a preapproved construction financing rider as part of the clean air, clean jobs act. At the end of the year the rate that we were collecting, that was about $5.9 million a year. That will be annual recurring revenue and we got a $1.2 million on top of that. It's still not a good decision. We are very disappointed in it but it's not $1.2 million of revenue on a $63 million asset.

At this time I would like to turn the call back to David Emery for closing remarks.

All right. Well, thanks for your participation on the call today, everyone. Unfortunately, we are out of time today but thanks for your continued interest in Black Hills and have a great rest of your day.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.