Black Hills' (BKH) CEO David Emery on Q2 2014 Results - Earnings Call Transcript

Aug. 6.14 | About: Black Hills (BKH)

Black Hills (NYSE:BKH)

Q2 2014 Earnings Call

August 06, 2014 11:00 am ET


Valerie Simpson -

David R. Emery - Chairman, Chief Executive Officer and President

Anthony S. Cleberg - Chief Financial Officer, Principal Accounting Officer and Executive Vice President


Matthew Davis - Crédit Suisse AG, Research Division

Nicholas Yuelys

Mathew Barnett

David Arcaro - Sidoti & Company, LLC


Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2014 Second Quarter Earnings Call. My name is Jenade, and I will be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to Ms. Val Simpson, finance manager of Black Hills Corporation. Please proceed.

Valerie Simpson

Good morning, everyone. Welcome to the Black Hills Corporation's Second Quarter 2014 Earnings Call. Today with me are Dave Emery, Chairman, President and Chief Executive Officer; and Tony Cleberg, Executive Vice President and Chief Financial Officer.

Before I turn over the call, I need to remind everyone that during the course of this call, 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 website and our most recent Form 10-K and Form 10-Q 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 now turn the call over to David Emery.

David R. Emery

Thank you, Val. Good morning, everyone. Thanks for joining us this morning. I'll start on Slide 3 of the webcast deck for those of you who might be following along. Again, we'll follow a similar format to previous quarters, I'll give an update on the quarter, Tony Kleberg will give an update on the financials for the quarter and then I'll talk about the strategic overview and more of the forward-looking strategy issues.

So moving on to Slide 5, highlights from the second quarter. From a business perspective, we have relatively normal weather in the quarter in utility service territories compared to colder-than-normal weather last year. I would say this year is characterized by a little bit warmer weather in April, a little colder in June but not far out aligned with normal.

Highlights for the Utilities. It's been a very busy quarter for our Utilities. We've got a lot going on. Recently, Black Hills Power filed for approval in both Wyoming and South Dakota to construct a new 144-mile, $54 million transmission line that will go from Northeast Wyoming to Rapid City, South Dakota. That's a project we hope to complete in early 2016, pending approvals, right-of-way acquisitions and things like that.

Cheyenne Prairie Generating Station, our new power plant under construction in Cheyenne, Wyoming, is on schedule and within budget. We expect commercial operations on October 1. The associated rate cases for that plant in both South Dakota and Wyoming are progressing well. New rates should be in effect in both jurisdictions on October 1, the first date of commercial operation.

July 31, the Wyoming PSC approved new rates for Cheyenne Light for the plant based on a 9.9% return on equity and 54% equity in the capital structure. A pretty favorable result for us, one we're satisfied with.

We also completed permanent financing for the plant. Black Hills Power and Cheyenne Light both entered into agreements on June 30 to issue a total of $160 million in first mortgage bond financing. The closing date for the sale of those bonds is expected on October 1, also coincident with the date of first operation.

Moving on to Slide 6, a continuation of our Utility highlights. Cheyenne Light received FERC approval to establish some new rates for transmission services on favorable returns on capital structure. Cheyenne Light, during the quarter or just after the end of the quarter, I guess in July, set a new all-time peak load, beating the previous load by about 6 megawatts or so.

Colorado Electric issued an RFP for about 42 megawatts of seasonal firm summer capacity for the summers of '17, '18 and '19, and then a request for up to 60 megawatts of renewable capacity as well. Our Power Generation segment has submitted both solar and wind bids in response to that RFP. We'll see how we fare as the utility conducts its analysis of bids and bidders.

During the quarter, both Colorado Electric and Kansas Gas filed rate cases during the quarter. Both are progressing well and kind of according to schedule.

On Slide 7, highlights for our Non-Regulated Energy segments. Power Generation segment received FERC approval in July for the previously announced sale of our 40-megawatt CT II combustion turbine to the city of Gillette, Wyoming. That transaction closing is expected by the end of the month. That transaction also includes an economy energy agreement with Black Hills, where if we can purchase energy for the city of Gillette cheaper than they can generate it with that turbine, we split the cost savings. That agreement will continue for 20 years. Should be a good arrangement for Black Hills over the long haul.

On the Oil and Gas front, in June, we commenced drilling in the southern Piceance Basin on 2 of the 6 horizontal wells that we plan to drill in the Mancos Shale formation this year. Operations are progressing well, and we expect good completions there this year.

On the Corporate front, the board declared a dividend of $0.39 per share last year -- last week, equivalent to an annual dividend rate of about $1.56. In June, Fitch upgraded our company's corporate credit rating to BBB+ with a stable outlook. Now 2 of the 3 agencies have us rated at the equivalent of a BBB+ credit rating. Pretty significant improvement over the last 1.5 years or so from BBB- at all 3 agencies. And then in late May, we amended and extended our $500 million unsecured revolving credit facility at improved pricing. That's a 5-year deal, also has a $250 million accordion feature.

On Slide 8, financial highlights for the quarter. We earned $0.44 a shares as adjusted compared to $0.41 per share in the second quarter of 2013. A pretty strong increase of 7% year-over-year. A pretty good growth given the relatively mild weather in the quarter.

Slide 9 provides a reconciliation of the second quarter 2014 income from continuing operations as adjusted to the second quarter 2013 results. In a nutshell, most of our businesses improved year-over-year. The exception was the Gas Utilities segment early due to a return to a more normal weather compared to a very cold second quarter of 2013.

Now I'll turn it over to Tony Kleberg for financial update for a quarter.

Anthony S. Cleberg

Thank you, Dave. As Dave mentioned, second quarter 2014 financial performance improved compared to the same period in 2013, and that's due primarily to an improvement in interest expense. As you'll recall, the weather helped us outperform in the first quarter, and in the second quarter, we gave some of it back due to mild weather, yet we achieved a 7% increase year-over-year in our earnings per share. Just looking at the first 6 months of 2014, our earnings per share improved by 19% over the same period in 2013.

Moving to Slide 11, we report GAAP earnings and reconciled to earnings as adjusted, a non-GAAP measure. We do this each quarter to isolate special items and communicate earnings that we believe better indicates our ongoing performance. This slide displays the last 5 quarters, and during the second quarter of 2014, we had no special items. So our GAAP earnings per share of $0.44 compares to the 2013 as adjusted earnings per share of $0.41. The 2013 as adjusted earnings per share excluded a mark-to-market gain of $0.28 on interest rate swaps that we settled near the end of last year.

Slide 12 displays our second quarter revenue and operating income. Later I'll give more color about the year-over-year changes by segment. But here, the main point is that we are predominantly a regulated business, generating about 80% of our operating income from our Utilities in the second quarter. Our operating income declined by 5% or $2.4 million compared to the same period in 2013. Milder weather in our gas utility territories lowered the operating income by $4.1 million compared to 2013. The impact of the mild weather was partially offset by better performance in our Power Generation and our Oil and Gas segments.

Slide 13 displays our second quarter income statement. As you'll note, our interest expense declined by $5.5 million. This resulted from 2 actions taken in the fourth quarter of 2013. One, we refinanced debt at lower rates. And two, we settled $250 million worth of interest rate swaps. Settling the swaps eliminated monthly interest charges.

Another point is while our operating income declined by about 5% due primarily to weather, our EBITDA declined less than 1%. Comparing the first 6 months with 2014 to the same period in 2013, EBITDA and operating income improved in that mid-5% range.

Moving to Slide 14. The left side of this slide displays our Electric Utilities segment. Our second quarter revenue increased by $3.9 million compared to 2013 due to primarily higher fuel costs. Those margins were comparable to the prior year, reflecting increased riders and higher industrial demand, partially offset by lower residential and commercial demand. Also we had planned and an unplanned outage that lowered our plant availability and lowered our off-system sales margin by $600,000 compared to the prior year. The lower residential and commercial demand reflected the impact of both lower heating and cooling days. From our perspective, it wasn't cold enough in April and it wasn't hot enough in June. With flat margin and higher expenses for employee costs and property taxes, our operating income declined by $700,000 in the Electric Utilities segment.

Looking at the right side of the Slide 14, you'll note Gas Utilities revenue declined by $3.3 million, resulting from lower demand caused by the mild weather. For the quarter, heating degree days were 5% above averages, but compared to the same period in 2013, the heating degree days declined by 16%. Our O&M expense increased year-over-year by $1.6 million, primarily due to employee costs, compared to 2013 second quarter operating income declined by $4.1 million. The residential and commercial dekatherms sold decreased year-over-year by 29%. As you will recall, last year, April and May were much colder than normal in our service territories and 2014 was milder. So overall, our Utilities had improved rates but the mild weather dampened performance compared to 2013. In our Utilities, both Gas and Electric, we continue to see about 1% annual customer growth.

Slide 15, our next segment, Power Generation's operating income as adjusted improved by $1.1 million compared to the prior year. During the current quarter, Power Generation saw strong operational performance, good cost management and improved prices for the purchase power agreements.

Moving to the right side of Slide 15. Coal Mining segment saw the second quarter operating income flat with 2013. The tons sold declined by 2%, prices increased by 4%, mostly offsetting a 5% increase in the mining costs. The stripping ratio, which increased from 0.86 to 0.95, slightly increased our overburden removal cost. As a reminder, over 50% of our coal production is priced on a cost-plus basis. The Mining segment is performing as expected.

Moving to Oil and Gas on Slide 16, we started to see improved performance. Our overall second quarter production increased by 15% compared to the same period in 2013. Breaking down our production improvement, we saw a 3% increase in natural gas, 41% increase in oil and 97% increase in natural gas liquids. From a cost perspective, our Q2 O&M expenses increased by only $244,000, and the DD&A increased by $2.1 million compared to '13.

From the operating income standpoint, we reduced our loss in this segment by $1 million compared to the same period in 2013, and this is primarily due to production increases and about 12% increase in our net average price received. The depletion rate increased by 30% compared to Q2 of 2013 due primarily to adding higher cost oil drilling to our cost pool for non-operated wells.

Sequentially, the first quarter to the second quarter production increased by 12%, natural gas increased 5%, oil by 24% and natural gas liquids increased by 55%. However, the net average price received decreased by 11% from the first quarter. Prices declined for natural gas by 5%, oil by 14% and NGLs by 32%. So with the production increase and the price decline, our Q2 Oil and Gas revenue was flat compared to the first quarter, and the $500,000 improvement in the operating loss resulted from lower O&M costs.

Slide 17 is our capital structure. And we appreciated Fitch's upgrade of our credit ratings during the quarter. And as Dave mentioned, at the corporate level, we have Moody's and Fitch at BBB equivalent -- or BBB+ equivalent and S&P at BBB flat. At quarter end, our net debt-to-capitalization ratio was flat with the year end at 53%. With the cash flow from operations and our debt capacity, we have ample funding available for capital expenditures and dividends for the next year.

Slide 18, just to note, we did reaffirm our 2014 earnings guidance to be in the range of $2.65 to $2.85.

And moving to Slide 19, just to conclude, our second quarter [indiscernible] is to lay a path for solid earnings growth. If you look at our projected midpoint for 2014 earnings guidance, we expect to deliver double-digit growth for our shareholders, an accomplishment that we consider very important.

And with those comments, I'll turn it back to Dave.

David R. Emery

All right. Thank you, Tony. Moving forward here on strategic objectives on Slide 21. As we introduced last quarter, we group our strategic goals into 4 major categories. Now the overall objective is being an industry leader in essentially all that we do. Those 4 categories are profitable growth, valued service, Better Every Day and a great workplace.

Slide 22, strong capital spending drives our earnings growth. We project strong spending far in excess of depreciation during the next several years and expect that trend to continue. But it has been and will continue to be a driver of our earnings growth.

Slide 23 provides detail related to the historical and forecasted capital spending by business segment. It gives you an idea kind of various facets of our growth throughout our subsidiaries.

Slide 24 is a subset of the information on Slide 23, simply providing a little more detail for some of our select major utility projects, including a couple that are beyond our 2016 detailed capital spending forecast.

Slide 25, again, helping drive our strong earnings growth in the '14, '15 time frame is our Cheyenne Prairie Generating Station. As I've said earlier, that $222 million project is on time and on budget for an October 1 in-service date, going exceptionally well and will be commencing firing turbines and selling test energy and things here in the next couple of months prior to commercial operations in October. Everything is going according to plan.

Slide 26, our Oil and Gas assets offer substantial value upside. From a strategy perspective, we plan to prove up and capture the value of those existing oil and gas properties, and also continue to pursue some disciplined oil exploration, primarily in plays that have impactful reserve potential.

This year, we're really focused on the execution of our Piceance Basin and Mancos drilling program. Our plan there this year is to drill and complete 6 wells in 2014 and another 6 wells in 2015. This year, we've commenced drilling the first 2 of those 6 wells in our 2014 program starting in June, again, according to plan.

With the result of our 2014 and '15 program, we hope that by late '15 we'll be able to consider strategic options for that play. We've talked about these before, but they can include many things, but including and not limited to select property divestitures, joint venture programs with properties, including some of those reserves are drilling in a cost-of-service gas supply program for our electric and gas utilities and certainly several other options or combinations of those options. But before making those, we really need to complete at least next 6 wells this year and 6 next year to really get a handle on the potential value of those properties before we make strategic decisions.

Slide 27 provides a little more detail on our 2014 Oil and Gas plan. I won't reiterate those, but suffice it to say, things are going according to plan.

One thing I'd like to mention is there has been a lot of attention focused in Colorado on some of the anti frac-ing ballot initiatives there. I was pleased to hear that earlier this week, Governor Hickenlooper in Colorado announced a deal with the proponents of anti frac-ing ballot initiatives to essentially remove those from the ballot this fall. In exchange for that, the Governor will appoint a special task force who will make recommendations, if necessary, to the legislature this winter regarding oil and gas activities in the state. Such things as set back distances from communities, residential areas, things like that. But I'm very pleased to see a good common-sense approach prevail in a state like Colorado where oil and gas is so critical to the state's economy. I think, again, common sense prevailed there, and it should. So positive result.

On Slide 28, we're very proud of our dividend track record. We've increased our annual dividend to shareholders for 44 consecutive years. Despite our aggressive capital spending, at least maintaining our dividend track record is very important from a priority perspective.

Slide 29, I mentioned this already, but during the quarter, Fitch upgraded our corporate credit rating. Again, as Tony mentioned and I mentioned earlier, we now have 2 of the 3 agencies that the equivalent of a BBB+ and one at BBB flat. A very positive result for the company. I think it shows the continued confidence in our ability to generate strong earnings and cash flows going forward.

Slide 30 provides a summary of our pending regulatory activity, much of which is rate case related, I have discussed a lot of that. In those rate cases, we're seeking a fair return on a substantial capital investments we've made in our Utility businesses primarily to better serve our customers. The update is pretty self-explanatory, so I won't elaborate anymore on that.

Slide 31 focuses on our operational superiority. We've got truly superior power plant availability and starting reliability compared to our industry peers. The slide also demonstrates that we have a very modern generation fleet with the completion of Cheyenne Prairie on October 1, literally an average age of about 12.5 to 13 years, which is pretty phenomenal, that positions us extremely well related to all the EPA activity related to emissions both from MATS rule and CO2 rules, et cetera.

Slide 32 exhibits, again, exceptional operational performance on our Utility businesses relative to sales [ph], and also demonstrates some things we've done to improve our customer's experience on how they deal with the company every day. Substantial improvements in those customer service areas, on-time rates for calls and field operations reducing truck rolls and things like that through our AMI system implementation.

And finally, Slide 33 illustrates a tremendous safety record that we've really been focused on in the last several years. And it also highlights again the quality of Black Hills Corporation as a workplace. For the third time in the last 5 years, our IT group has been named one of the Best 100 Places to Work in Information Technology, something our IT folks should be very proud of.

Slide 34 is our scorecard. We show this to you every quarter. Again, this is our way of holding ourselves accountable to you, our shareholders. We set forth our goals at the beginning of the year and note progress as the year goes on. Progress has been excellent to date according to plan.

That concludes my remarks. I would be happy to entertain any questions.

Question-and-Answer Session


[Operator Instructions] Your first question comes from the line of Dan Eggers with Crédit Suisse.

Matthew Davis - Crédit Suisse AG, Research Division

It's actually Matt Davis. I was wondering if we could just touch upon the Oil and Gas business and the decision to drill the 6 additional wells in 2015. Correct me if I'm wrong, but I believe in previous quarters, we had really just focused on the 2014 drilling program, and then we kind of come to like a value decision around the first quarter and maybe of 2015 and then some kind of strategic decision later on in the year. I just wanted to understand the decision process around that.

David R. Emery

No, I don't think there's been any change there at all, Matt. I mean, we've been pretty focused on a couple of years worth of solid drilling results. As we've discussed in the past, what it really boils down to is we need to drill enough wells to be comfortable with the repeatability of results, both the physical side, the drilling and completion and the costs associated with that; and then certainly, the production and reserve booking side of that as well. We're feeling very confident about the progress we're making, continuing to get more and more efficient at our drilling and completion operation. But with a play as large as this, it's going to take some wells to get that established. Even if we drill all this, it's only like 16 wells in a play that we've drilled, so it's not really that many, and I don't think it represents any change in our plan at all.

Matthew Davis - Crédit Suisse AG, Research Division

And will you guys be able to kind of firm up and provide some information around well design and spacing that kind of information sometime earlier in 2015, or is that going to have to wait till the end of 2015 once you're done with both of those..

David R. Emery

To the extent that we continue to drill, we'll provide updates. One of the benefits at least of the first 3 wells we're drilling this year is we're not in an area where we're bound by a partnership confidentially agreement. So we would intend -- once we have, say, cost through casing point, pre-completion, we would probably release some of that information and compare it with the information we've provided last year. Possibly some of that information will probably discuss at our Analyst Day. That's typically a good venue for going into a little more detail. We don't typically have time on earnings call to spend too much time on those issues.


Your next question comes from the line of Nick Yuelys with Gabelli & Company.

Nicholas Yuelys

I was just wondering if you could provide a little more color on the electric demand growth you're seeing in Cheyenne. Is that data center-driven or is it more economic growth in and around the city?

David R. Emery

I would say it's a little of all of the above. Cheyenne just had pretty strong growth relative to most of our service territories. It has been for several years, getting a lot of business overflow from the front range, if you will, much more pro-business environment in Southeast Wyoming than in Colorado and, I mean, a more favorable tax environment and everything else, and Wyoming has been pretty aggressive at trying to attract business to Cheyenne. The Cheyenne LEADS group, the economic development group there did a fantastic job and our folks have been working hand-in-hand with them. Certainly, the data center business is helping. Several years ago, we started on National Center for Atmospheric Research data center there. Microsoft has a new data center that's been up and running for a couple of quarters. That's a pretty significant increase in load, and Microsoft announced with the Governor of Wyoming here a month or 2 ago a pretty significant continued expansion in Cheyenne as well. So I think all of those signs plus just an increase in commercial business overall are good positives from a forward perspective for Cheyenne Light. It's been a real good territory. Wish it was a little bigger. Thinking about 200-megawatt system.

Nicholas Yuelys

Okay, great. And then I guess just on the Oil and Gas side. Crude volumes and NGL volumes were up pretty significantly year-over-year. Is that mostly related to the non-operated Bakken wells, or is that coming from some of the Piceance wells you drilled at the end of last year?

David R. Emery

It is a combination of both. The non-operated did a little stronger on the oil, but we're also getting some oil out of the gas wells that we drilled in the Piceance. In the NGLs, really the Piceance has helped that substantially.

Nicholas Yuelys

Okay, great. And then did I just hear you correctly that the first 3 wells you're drilling this year won't be subject to the confidentiality agreement?

David R. Emery

Yes, that's correct. And if possible, all 6 won't, but for sure, the first 3 won't. So as we have reasonable information, we'll be releasing it probably in our quarterly calls, and like I said, probably try to go into a little more detail if we have some good numbers on our Analyst Day in September. One other comment, Nick, is the 2 wells that we drilled last year, we're not going to disclose production on those 2 wells every quarter. But suffice it to say that they're following the type curves that we've put out previously for those Piceance gas wells, I think it's back in the deck in like Slide 50 or 51, somewhere back there. But they are -- both wells are following the production profile that we forecast.


Your next question comes from the line of Mathew Barnett with Capital Jet (sic) [Jet Capital].

Mathew Barnett

I just had a couple of questions. The first one on Oil and Gas which you'd touched on, on the NGLs. Just by the math, it looks about 30% of what you produced was NGLs. Is that in the right range of numbers?

David R. Emery

Probably in the ballpark, yes. We don't disclose this -- we don't have specific production on those 2 wells in the data, but that's probably in the neighborhood. Very strong liquid yields there.

Mathew Barnett

And then when I look further on the deck that you have on the back, you outlined in oilier zone, that looks to be about 50% to 60% of your acreage. Is that in the ballpark as well?

David R. Emery

Yes, roughly, but we showed that map in there based on current well control, and part of our delineation drilling program here is to really get a better handle on where that oily zone, if you will, really is, the more liquids-rich area. There's limited production in the Mancos in that region and we're kind of extrapolating between those wells to draw that map. So part of what we're doing in drilling these wells is testing which areas of our acres really are more liquids-rich than others. But based on the map, I think your observation is correct. But again, remember that the map is not based on a lot of well control, so it's going to be subject to reinterpretation as we continue to drill wells in play and as other operators drill wells in the play also.

Mathew Barnett

That's great. And then separately, you indicated the EURs of a range of 6% to 9% based on your drilling in 2011, 2013. It seems like you're going for longer laterals now. Should investors be more focused at the upper end given the type curve you're pointing people to?

David R. Emery

Yes, most our plans are to drill 9,000-plus or so foot laterals. It's kind of what we're focused on now. Earlier, we will drill in the 5,000 to 6,000 foot laterals and I think the results that we've seen, as well as the results that we've seen from other operators in the play continue to suggest that economics are better at that 9,000 to 10,000 foot lateral length range. So that's our plan. And again, from a completion standpoint then, we're pumping frac job every 200, 250 feet or so in that lateral on a section.

Mathew Barnett

Okay. So the upper end of the EUR range is kind of more indicative of the plan, if everything pans out?

David R. Emery

Yes, again, our wells are pretty early. But based on the type curve work we've done and analysis for the other wells, that's what we believe at this point.

Mathew Barnett

Okay. And then just shifting to the Utility side, you spoke about the Microsoft data center. Can you give -- that looks to be coming online in summer of 2015. Can you give us a sense of kind of what that means for load growth?

David R. Emery

Well, we haven't talked specifically about it because we haven't finalized any definitive plans with Microsoft. They've talked about substantially increasing their presence in the state; they've talked about adding a lot of capacity there. We're still working with them on the specifics of how much load they're talking about, so we're really not in a position yet to disclose what that load growth would be. Their plans are, at least tentative plans, are a couple, 3 multiples of what they currently have, maybe even more than that. But when we know those plans and they have disclosed the size specifically of the data centers they're going to add, we'll provide a little more color on it, but we're still in discussions with them about that at this point.

Mathew Barnett

Do you know how much you currently supply to them in the current center?

David R. Emery

It's between 10 and 15 megawatts.


Your next question comes from the line of David Arcaro with Sidoti.

David Arcaro - Sidoti & Company, LLC

You've talked a little bit about rig availability before. I'm wondering if you had any issues with the 2 wells you brought on? And would you anticipate any issues with availability, I guess, for the coming 4?

David R. Emery

Well, we have a rig under contract to drill all 6.

David Arcaro - Sidoti & Company, LLC

Okay, got it. Let's see. Also could we get a current update on status of the coal price negotiations? Are there any market catalysts that you're still waiting for at this point? Or is it just finalizing the deal?

David R. Emery

No, there are essentially 3 components to that price and we've negotiated 2 of the 3. The third one should be soon. And once we agree on that price, it'll be effective July 1. So we expect to reach agreement, hopefully, in the next month or 2 on that one. It's just kind of an issue of timing and getting the parties together to finalize negotiations. But I think it will be coming soon and hopefully we'll get it in place. And like I said, it's effective July 1 when we finally get it in place.

David Arcaro - Sidoti & Company, LLC

Got it. So it would be retroactive essentially covering the volumes?

David R. Emery

Correct. That is correct.

David Arcaro - Sidoti & Company, LLC

I'm wondering if you could give your current thoughts on the EPA's proposed carbon emission regulations. I guess what's your approach and any insight into what you -- what to expect at this point in terms of maybe capital needs, or really, what you see coming down the line?

David R. Emery

Too early to say what we think is going to happen in the individual states that we operate in. We're very actively participating in the process, whether with EEI or whether it's in Colorado, South Dakota or Wyoming with the various state agencies. You really need to get all the players in each state together to really discuss the issues and concerns there. Frankly, in South Dakota, we don't have any coal-fired generation in South Dakota anymore, so we really have very little issue in South Dakota based on what we see today. Still assessing the situation, but we just don't have any baseload fossil-fired units in South Dakota, so should be kind of a nonevent there. Wyoming, we've got one of the most modern fleets in the country, frankly, coal fleets. All 4 units there are 1996 vintage or newer, all extremely low emissions for everything but CO2. If we have to reduce CO2 emissions at those plants, we believe we can do that through relatively economic means, whether that's coal-firing a portion of natural gas or something. We're investigating all of those alternatives. It certainly would have a rate impact on customers, but we really don't know what we would need to do, if anything, until we know what the other players in the state are going to do. And primarily those are based in electric, the coop and PacifiCorp. And we're still working our way through that process in the state, meeting with the state Public Service Commission, the State Department of Environmental Quality and any other players, so a little too early to tell what's going to happen there. Colorado, very similar circumstance. We really don't have any coal units there anymore either, we don't. We retired our W.N. Clark in Cañon City. We've got a couple of combined-cycle gas units there. But beyond that, frankly, there's not a whole lot we will need to do or be expected to do. Again, you're looking at a discussion with the state. The other players in the state, notably, Tri-State on the coop side and of course, excel on the investor-owned side, so a little early. But I think from a relative perspective, compared to most of our industry peers, I think we're in very, very good shape. That being said, I think the rules are extremely onerous, and if it goes through, it's going to have a real dramatic negative impact on customers. Ours is less so than most of our peers, but it's a very, very complicated and very, very expensive rule, if it gets completed as proposed.


[Operator Instructions] And we do have a question from the line of Dan Eggers from Crédit Suisse.

Matthew Davis - Crédit Suisse AG, Research Division

I'm back again. Can you just talk about the process and timing for the approval of the transmission line. And then additionally, if in -- from Black Hills Power? And then additionally, is there any other opportunities outside of what you guys currently have in your plan that you're currently evaluating?

David R. Emery

Yes, the process and timing is, we filed with both commissions -- South Dakota is a little different approval because they don't have what you would consider to be a formal Certificate of Public Convenience and Necessity process. But we would expect approval somewhere in the year-end time frame in both South Dakota and Wyoming. There's no guarantee of that. But I think the line is pretty well supported. So we don't expect a lot of trouble there getting approvals. We also expect to have federal approval relatively soon, which we've been talking a little bit about this line for probably almost 2 years now. We haven't specifically filed for approval yet. We've been doing all the preplanning work primarily with the Fed, and a lot of that is we've got the Bureau of Land Management, a lot of United States Forest Service, National Forest Land to cross and a few others, National Grassland a little bit in Wyoming. I think we're a pretty good shape relative to Federal okay, and just need the approval from the 2 states. We would then hope to construct the line in '15 and have it in service in early '16. Again, that assumes all of our right-of-way acquisitions get completed on time and some of those things. And it's a little early. We don't have all our rights-of-way secured yet. We're working on it. We don't expect major problems, but it just takes time. But early '16 is kind of our planned in-service date right now. Related to other projects, we're always looking at some of the smaller transmission projects, and the nice thing about those is we do have some riders in place. And if you look at our capital schedule, the detailed utility project, one in particular, there is a couple of smaller projects kind of way down on the bottom of the list that are in the 2017 and beyond time frame. Certainly, those we're contemplating or they wouldn't be on the list. More than contemplating, we're working on those. We have others that we may do, but I would say, not a lot, unless we see call substantial load growth or something that would lead us to have to construct additional transmission. We'll be doing some incremental projects. The largest utility growth project that we've been looking at really is, as I mentioned earlier in the Oil and Gas Segment about our cost-of-service gas program for gas supply for both our Electric and Gas Utilities. We're working on that, we're evaluating that, looking at whether we could include some of our own internal drilling in a program like that. Not ready to propose anything yet, but certainly, we're seeing some positive signs in other jurisdictions. We believe our Oil and Gas expertise sets us up to do that very well if we can get to a result that we really think will be good for shareholders and probably try to get something going on that front.


And at this time, we have no further questions. I would now like to turn the call back over to Mr. David Emery. Please proceed.

David R. Emery

All right, thank you. Thanks for your interest in Black Hills. Thanks for your time and attention this morning. Again, we're pleased with our quarter relatively mild weather, but we still improved earnings 7% over a pretty good quarter last year, so we're pretty happy about that. Operationally everything running extremely well, all according to plan. And we look forward to continuing to report strong results in the future. Thanks for your time and attention. Have a great rest of your week.


Thank you for your participation in this conference. This concludes the presentation. You may now disconnect. Have a great day.

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