Black Hills Corp (BKH) 2011 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2011 second quarter earnings conference call. My name is Janea, and I will be your coordinator for today. At this time all participants are in listen-only mode. Following the prepared remarks, there will be a question-and-answer session.

(Operator Instructions)

This conference is beings recorded for replay purposes. I would now like to turn the presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation.

Good morning, everyone. Welcome to the Black Hills Corporation 2011 second quarter earnings call.

With me today are David 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 you 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 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 will now turn the call over to David Emery.

Thanks, Jerome, good morning, everyone. Today our format will be consistent with our previous quarterly web cast, and then I'll give some highlights of the quarter, Tony Cleberg will cover a discussion of the financial results, and then I come back on and discuss strategy and key earnings growth initiatives for the future, followed by question-and-answers at the end.

Moving on to slide 5 for those of you who are following along on the webcast presentation. A summary of the second quarter for 2011. We had a very good quarter. Net income as adjusted was up 68%, compared to the same quarter of last year. The adjusted earnings per share was $0.32 compared to $0.19 in the second quarter of 2010. The improvement was driven largely by our utilities, primarily related to the impact of 5 utility rate cases completed during 2010 and throughout the year. We are realizing the full benefit of those now in this quarter.

Income from our non-regulated energy businesses was down slightly compared to the second quarter of 2010. We had increases in power generation and energy marketing, which were slightly more than offset by decreases in coal and oil and gas.

Moving on to slide 6, utility highlights for the quarter, and there is quite a few, utility net income was up 106% compared to the prior year, really good result there. We had the implementation, as I mentioned before, of new rates in 5 different jurisdictions, really driving that earnings improvement in our utilities.

In June, the South Dakota PUC approved an environmental rider for our Wyodak plant that has annual revenue impact of about $3.1 million for Black Hills Power. That was the result of our $25 million share of the capital investment in that facility, which is operated by Pacific Corporation., which covered the installation of some pollution control equipment. Construction continues on time and on budget for the Colorado Electric generation facility in Pueblo Colorado, and the rate case was filed on that and is progressing. We will talk more about that later.

Progress continues on several previously-announced utility growth investment opportunities. The first one is our certificate of public convenience and necessity in Colorado to add a third utility-owned gas turbine for $102 million at the Pueblo site. That turbine will replace the W.N. Clark facility, which is a coal-fired facility in Canyon City Colorado, that will be retired in the next few years. Colorado Electric reached a settlement with all the parties in mid-July related to our filing and proposal to rate base our 50% share of a 29 MW wind project in Colorado. There is a hearing on that with the Colorado PUC on August 8 and we expect an order sometime there after.

Also in Colorado, we had proposed construction of what we refer to as our Southern Connector transmission project, about a $16 million investment. We asked the Commission essentially to determine that that was in the normal course of business, which means we can proceed with construction without going through a certificate of public convenience and necessity hearing process. So we will proceed with that project as well.

On Monday, Cheyenne Light filed an integrated resource plan and certificate of public convenience necessity in Wyoming to build a new 120-MW gas-fired power plant in Cheyenne, within the city limits for $158 million. That process will take several months to get through the regulatory process, but we will be filing air permits and things in conjunction with the CPCN process.

We still have, as we've talked about on previous calls, 2 more integrated resource plans to file for our other electric utilities, Black Hills Power and Colorado Electric. We do expect those resource plants to recommend the additional generation. For Black Hills Power, we are really believing that we will have to replace our older coal fire generation due to the new EPA boiler rules, which we've discussed on previous calls. We have about 84 MW of plants that will have to be retired in early 2014 under those rules. For Colorado Electric, the resource plan there will deal with primarily the addition of renewable resources to meet the state's 30% renewable energy standard.

Finally, for our electric utilities, we are off to a good start in the third quarter. In mid-July we set new peaks at all 3 of our electric utilities, and by a fairly significant margin. At Colorado Electric, our peak was about 2% higher than the previous one, Cheyenne Light was about 3% higher, and Black Hills Power was nearly 5% higher than the previous peak load set in that utility.

Moving on to slide 7, the non-regulated energy highlights. Power generation earnings are up, construction continues to progress very well on the IPP plant, located at our Pueblo generation site, that's still on schedule to begin operation January 1.

Energy marketing showed quite a bit of improvement this quarter, as we have been discussing in the several past quarters, we have been focused on diversifying our marketed commodities. Really to lessen our dependence on natural gas marketing for earnings in that subsidiary, those efforts are starting to payoff. This quarter we had increased volumes and positive gross margins contributions from all of our commodities, natural gas, crude oil, power and coal. Also consistent with our prior statements, we've maintained our consistent risk limits, bar limits and even our credit facility size there. So although we've increased the commodities marketed, we are not increasing the overall risk we are taking in that business.

On the coal mining front, consistent with our first quarter discussion, we continue to be challenged by higher costs there due to our location in the mine and several other factors. Tony will talk about a little bit about some of those in the financial discussion, but we are working hard to reduce those costs. We are starting to make progress in that regard, but we do expect the challenges at the mine to continue at least throughout the rest of this year, probably a little longer.

Slide 8 on the corporate summary side, a couple of significant items there. We did close a $150 million 1-year term loan. That term loan will reduce borrowings on our corporate credit facility on our revolver and save us about $700,000 in 2011 interest expense. The Board approved a dividend of $0.365 a share last week, and then finally, we continue to expect to settle our equity forward transaction in the fourth quarter of this year.

Slide 9 is just simply an updated timeline for our key strategic and growth initiatives. We have shown you this in the past, and this is an updated version for current activity.

Now I will turn it over to Tony Cleberg for a discussion of financial results for the quarter. Tony?

Thank you, Dave. Good morning.

As Dave indicated, our overall second quarter financial performance delivered strong year-over-year improvement. Our operating income improved by 38% over last year's second quarter, with the utilities increasing 46%, and our non-regulated group improving 6%. Overall, our EPS on as-adjusted basis improved 68% over the second quarter of last year. On later slides I will address the drivers in the quarter.

Moving to the EPS analysis on slide 11. We adjust our income from continuing operations to display a non-GAAP earnings measure that we feel better communicates our relevant performance. Special gain and loss items are excluded to compute net income or EPS as adjusted. This slide displays the last 5 quarters.

The only special item included in Q2 of 2011 was the addition of $0.13 for a non-cash unrealized mark-to-market loss on our $250 million of interest rate swaps. So with that adjustment, the quarter's EPS as-adjusted, was $0.32 per share, which compares to $0.19 in 2010. Looking at last year's second quarter, the reconciliation includes a $0.41 addition for the unrealized mark-to-market loss on the same interest rate swaps. So with the $0.13 improvement, the trailing 4 quarters EPS now equals $1.70.

Slide 12 displays income statement for the second quarter of 2011 and 2010, and as you'll note, our GAAP EPS improved $0.41. This resulted from a combination of improving operating income of $11.8 million, and improved mark-to-market of $17.1 million on our interest rate swap and an increase in interest expense, somewhat offset by interest expense increasing $600,000. The improved operating income I will discuss in more detail on a later slide, but in summary it reflects improved performance in both the utilities and the non-regulated group. The increased interest expense reflects primarily higher debt levels a we continue construction on the Colorado generation project.

Continuing down the income statement, the second quarter effective tax rate was 40%, for 2011, which compares to 37% in 2010. The higher tax rate during the quarter reflects the state income tax impact of an IRS settlement. If you look at the year-to-date effective tax rate of 35%, it is consistent with last year and reflective of a more normalized rate, which we respect for the remainder of the year.

Moving to the bottom line. The resulting second quarter 2011 GAAP EPS was $0.19 per share, compared to a loss of $0.22 per share in 2010. Looking closer at operating income, slide 13 display a segment roll-up of revenue and operating income for the second quarter of 2011 and 2010.

The electric utilities segment year-over-year operating income improved by $3.6 million, reflecting the benefits of earning returns on an increased rate base, recognized in last year's rate settlements. Overall, the MegaWatts sold during the quarter declined by 1% compared to 2010. So higher prices drove the improvement in operating income. Other changes in the MegaWatts sold included a 32% decline in contracted wholesale as the result of a large customer acquiring a direct interest in Wygen 3 for their resource needs.

The mega watts sold for off-system power sales increased by 4%, while the margins decreased by 37%, resulting in a slightly lower operating income compared to 2010. The low energy margins resulted from a overabundance of hydro power in the northwest and lower power prices, which are influenced by low natural gas prices.

Moving to gas utilities segment, for a shoulder quarter, we achieved exceptional performance. Operating income increased by $7.4 million over last year, a combination of volume, improved rates, and lower expenses drove the stronger performance. The deca-therms sold during the quarter for resident, commercial and industrial increased by the 22%. Our gas territories were colder than normal in 2011, and the drought in Western Kansas supported higher gas usage for irrigation. One of the drives of the operating income was the improved margins of $2.8 million, reflecting both last year's rate settlement and the quarter's increased volume.

Another driver of the improvement in operating income was $4.6 million of lower operating expenses. The lower operating expenses reflect over $2 million of improved efficiency. There was an $800,000 reduction in property taxes, and this was based on a settlement. Although our operating taxes went down about $800,000 was a catch-up from prior periods that we had recorded. Also there was about $1 million of shifting of allocated G&A expenses to the electric utilities.

As I've mentioned in the past, we allocate indirect G&A expenses to segments based on formula of assets, gross margin and employee cost. So as we construct the Colorado generation facility, more expense is allocated to electric utilities and the power generation segments. So to summarize, utility performance, both our electric and gas utilities, continue to perform well and delivered a great improvement in the quarter.

Moving to oil and gas our operating income was almost flat compared to 2010. The result reflected the combination of a 20% increase in oil volumes, and a 5% decrease in gas volumes and 12% lower received hedge prices for both oil and gas. Our depletion expense increased slightly year-over-year as we continue to add higher-cost oil wells to our depletion cost pool. These projects have strong economics at the current oil prices, however the cost pool is depleted over the average gas and oil production. The result is increasing depletion rates.

The next segment, power generation, increased by $2.5 million in operating income from 2010. During Q2 of 2010, Wygen 1 had an outage and related repairs expense, so much of the improvement from 2010 related to operating at normal operating levels. This segment continues to absorb more G&A cost prior to recording the revenue related to the Colorado generation that I talked about, the allocation of the G&A expenses.

Moving to the next segment, coal mining, our operating income declined by $4.7 million from 2010, as a result of higher mining costs. As we discussed, the various cost issues in the first quarter, and as we indicated, many of the cost issues will be with us throughout the year. The operating loss in the second quarter was an improvement of $1.6 million from the first quarter and was driven by better coal pricing. Cost improvements in the second quarter were hampered by severe wet weather, causing inefficiencies in the mines.

Our production volumes declined by 15% from the previous year due to forced outages at non-affiliated power plants. In July, we changed the operation of the mine from a daily 7-day-a-week operation to a 24-7 schedule. We believe that this will improve our efficiencies going forward. In addition, we are continuing to pursue various initiatives to improve our cost performance in the coal mine.

For energy marketing, our next segment, we reported operating income of $5.8 million for the quarter, an improvement of $3 million from 2010. All 4 commodities performed well during the quarter. We are encouraged that this diversified approach achieves a better balance in our energy marketing business, and reduces our dependency on fewer commodities. We achieved the second quarter results using less of the [Encircle] credit facility, and about the same level of invested capital. We reduced some of the shortfall that we saw in the first quarter in energy marketing, and we remain optimistic that by marketing our diversified set of commodities, we have an opportunity to exceed last year's annual performance.

So with the performance we saw in the second quarter, we are confirming our previous EPS guidance for the year, which ranges from $1.70 to $1.95. We made solid progress in the second quarter resulting in performance that was better slightly better than we expected. But with continued challenges at the coal mine and other risks, such as weather, we are leaving our guidance range unchanged from the first quarter. This range is based on net income, as adjusted, so there is no impact for special items such as the mark-to-market on the interest rate swap.

Moving to our capital structure on slide 14, this shows our capitalization. We feel our present capital structure supports our needs through 2011 into 2012. Our net-debt-to-capitalization ratio is presently at 57%, but giving consideration to the equity forward, the pro forma calculation for net-debt-to-capitalization is 52%, so our capital structure is in good shape. Our pro forma calculation assumes we delivered the shares under the equity forward at the end of the second quarter. So in conclusion, we are pleased with our overall financial performance in the second quarter, particularly in our utilities segment.

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

Thank you, Tony.

Moving on to slide 16. Our earnings and asset mix continues to reflect the strength of our utility businesses. We have spoken about that in the past, and really that's changed since 2008 when we acquired the five utilities from Aquila and divested of some of our non-regulated power plants. Continuing to show good strong operating income and a significant portion of our assets being from our core utility businesses.

On slide 17, we have a very clearly defined growth plan driven by substantial planned capital investments, particularly in our electric and gas utilities segments. That investment will drive strong earnings growth in 2012 and beyond.

Slide 18, our Colorado generation projects, which I spoke about briefly earlier, remain on schedule and on or ahead of budget for the 2 projects we've spent nearly $430 million to date out of a planned $487 million. The utility-owned plant is about 91% complete with construction, definitely on schedule to be in service by January 1, 2012. The IPP plant is about 77% complete, also on schedule to be in service by January 1.

The photo at the bottom of the page I think illustrates remarkable progress in 1 year. Literally we had the groundbreaking celebration for this plant in early August of last year. It literally was empty at that time. We were driving a few piles and that's it. So you can see really the tremendous amount of progress our construction folks have accomplished in just 1 year. Very tight timetable on that whole project, and they are doing extremely well relative to schedule and cost both.

Slide 19 is an assessment of proposed and final EPS regulations, and consistent with the information we showed you in the first quarter, and really tries to address the impact of certain either proposed or finalized EPA rules on a lot of our power generation facilities. There is really no change to that from the prior quarter. I just want to bring it up again, and as we've discussed, several of our facilities will be impacted by those rules some of which are not yet final. The utility macros are not yet final. I think the EPA's target is maybe by November to have finalized rules there.

Moving on to slide 20, I referenced this earlier, but we really have excellent long-term growth opportunities, starting in 2012 and well beyond. In addition to the $487 million project in Colorado, those 2 projects combined that will be in service in January 2012, we have announced another $303 million for 4 other utility projects that are either in ongoing regulatory processes or have been approved, as the case of this Southern Connector project where we don't need approval. A pretty substantial additional investments. Those 4 investments will come online between the fourth quarter 2012 and the first quarter of 2014. We will recognize the earnings growth associated with them.

The other 3 projects in the utilities side there are really pending completion of our integrated resource plans for Black Hills Power and Colorado Electric. We hope to move several of those project opportunities into the announced column, as well here, prior to year-end. On the non-regulated side, the key there is our oil and gas development dollars, and a lot of that is of course contingent on our ongoing strategy review for Black Hills Exploration and Production. We said previously we hope to announce the results of that before year-end and we are still on schedule to do that.

Slide 21 is an update on our Colorado electric rate request. We've asked for an effective date of January 1, 2012, and a $40.2 million revenue increase. We do now have a procedural schedule in place, discovery is underway. The Colorado Public Utilities Commission hearing is set to start on October 31. We expect some public and community input hearings to be conducted in the third and fourth quarters, and expect to have a decision by the Public Utilities Commission prior to year-end 2011. So the new rates can be effective on the commercial operations date of the facilities, which is January 1, 2012.

Slide 22 is an update on our oil and gas exploration and development drilling program. We've discussed the Mankas Shale gas opportunity in the past that underlies our acreage in the San Juan Basin and Piceance Basin. We are progressing on that effort. In the San Juan Basin, we've drilled our first Mankas test well. Drilled it, cased it, cemented it. We are currently completing that well and performing stages of our fracture stimulation. We would expect to have results of that well later in the year.

In the Piceance Basin, the first well has been drilled, cased, and cemented. It's waiting on fracture stimulation, water hauling and other things, probably will be stimulated early in the fourth quarter. The second Mankas test, we've completed the location, finished all the dirt work there, and are in the process of moving the rig to that site. Really should commence drilling hopefully over the weekend or by early next week. All three of those Mankas test wells, we hope to have good production tests and be able to release solid information on all 3 prior to year-end.

We are continuing our non-operated participation in the Bakken Oil Shale play in the Williston basin in North Dakota. It's been very good to us, the economics are great. We do have a small non-operated working interest in that project, so impacts are incrementally small, but as a whole, it's been a good opportunity for us.

Finally, we do have a small oil exploration program and we expend a pretty small portion of our overall capital project looking for new drilling opportunities. And typically at least in the last couple of years, we've been focused more on oil properties, primarily because of the low natural gas environment. I think we are pretty consistent with our oil and gas peers in that regard. We are the operator of 2 of these projects. So I thought I would mention on the call, because I know some of you look for drilling permit data and you're likely to see those wells. The first one is what we call our 6-mile anticline prospect, it's a vertical sandstone Sundance formation oil test in Goshen County, Wyoming, about 5000 feet deep.

The other one is what we call Freedom Dome, it's a heath shale -- it's an oil shale similar to the Bakken, but kind of north central Montana. In the process of drilling a strata-graphic test there, not necessarily intending to produce it, more related to taking a core sample in the heath shale and confirming that it would be a viable target for horizontal well similar to what is done in the Bakken. We have a little bit of activity going on there. Don't really expect any significant results to be announced, if we have any, probably prior to at least the end of the quarter, depending on what we find.

Slide 23 is just an updated score card on our key strategic objectives for 2011. This is something we have been doing for the last several years. It's our way of setting forth for you, our shareholders, our goals and measuring our progress towards those goals every year.

Finally on slide 24. In summary, the second quarter was a very good quarter for Black Hills Corporation. A very strong utility performance being realized primarily through the 2010 implementation of new rates in 5 different jurisdictions. As I said before, we've got significant capital growth projects progressing in several of our utilities, that will drive earnings growth in the 2012 and beyond timeframe.

On Monday we announced the new project, $158 million investment for Cheyenne Light, constructing a gas-fired power plant there. The Board approved a dividend payment of $0.365. That's consistent with the first quarter, which marks our 41st consecutive dividend increase. Finally, as Tony said, we've reaffirmed our 2011 earnings guidance which was previously released on May 10. We expect our adjusted net income to be in that $1.70 to $1.95 range.

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

(Operator Instructions) As a reminder, in order to get as many questions answered as possible we ask that participants reenter the queue after asking one initial question and one follow-up question. Daniel Eggers, Credit Suisse.

This is actually Kevin. Tony, with regards to the gas utility O&M, can you I guess explain the durability of it. Meaning that should the $2 million of efficiencies and the $1 million of G&A, become the new run rate, so the ongoing should be lowered by $3.5 million a quarter?

That's what I'd expect. We certainly got a little bit of a push just on the volume being up as strong as it is and in effect the costs being about flat. But those reductions, particularly the allocation, that is going to be an ongoing thing. The efficiencies, they should stay there, Kevin. The only thing is the property tax pick-up is more of a one-timer, but we had accrued that for that amount actually in 2009.

Were the efficiencies at 1 particular LDC?

No, it's really across the board. It's just a number of things that we are trying to do to just be more effective.

David, on the Mancos, I believe some of your neighboring EMPs, I think at Encanna and Williams, have already completed test wells. Can you offer color on what they are seeing, if I can reasonably extrapolate that onto your wells?

Without getting in to real specific details on their wells, think what we are seeing with the passage of time is that the results of the wells that are being drilled offset to our acreage are actually probably more encouraging rather than less encouraging. We are seeing pretty good reserve estimates from some of the wells, of course they are fairly early in production history, so those reserve estimates are still a little subjective. A lot of the numbers we are looking at are in the 6 billion to 8 billion cubic feet per well range, so that's pretty encouraging.

Assuming success at the Mancos, do you believe you can drill it yourself or given the scarcity of drillers in that market, do you think you will have to bring on a partner or just monetize the entire play?

We certainly have the capability to drill it ourselves. We've got very experienced people and they are doing a great job on the 3 test well that we're drilling ourself. We are investigating what we would want to do for alternatives there. We do believe that there are rigs available that we could potentially contract with for a longer-term program if we so choose. But bringing in a partner maybe a viable alternative as well, and really still evaluating those options. I think depending on what we get for well results and well economics might tend to drive us in one direction versus the other. So we won't probably won't be making that decision until we have a chance to thoroughly assess the result of our 3 test wells.

On the [Mancos], when do you give the following year guidance? Should we expect 2012?

Yes. We typically give it in conjunction with our third quarter earnings release; Kevin. So early November as a rule.

Andy Smith, JPMorgan.

Nice job on the cost control. I wanted to follow on a little more on the expense questions that Kevin was asking, I think I'm pretty comfortable with the gas utility. It looked like expenses at the electric utilities as well were down, not only year-over-year, which I guess a big piece is Wyodak, but it looks like it was down sequentially as well. I guess the question would be, are we seeing the same efficiencies at the electric business and is that something you expect to be repeatable. A little color there would be helpful.

From the electric standpoint, we are doing the same kinds of things to promote efficiencies and to capture cost savings in the electric utilities as we are doing in the gas utilities. So will we continue to see declines? Well, we are working the efficiencies to make sure that we are offsetting inflation.

On a data point, any sense of, you mentioned weather being favorable at the gas business, any sense of what that was in the quarter? I know it's difficult to tease that out sometimes. But any sense of what that was?

It's at least $1 million, Andy.

Last couple of questions, one is on the energy marketing business, not necessarily that volume's a great predictor of that business, but it looked like volumes were down, yet margins were up pretty nicely. We've heard some others in the industry talk about margins being under some pressure and what was going on there. Any more color you can shed on where you saw opportunities and maybe the sustainability of that, and what you were seeing in the marketplace at the marketing business?

The gas, the market conditions, were a little more favorable in the second quarter than what we have been seeing. Who knows if that will continue. On the other utilities, or on the other commodities, a lot of that is producer services. As long as they producing crude in the Bakken Basin, as long as people need coal out of PR V, and so long as small towns need power, we are able to put deals together and they are not 100% back-to-back, but that's what we try to do. So we feel that that business will continue on.

One last question, I know we're supposed to be limited to 2, but hopefully this is a short one. You mentioned weather impacts at the coal business impacting volumes. Has that depressed trend continued into July or has that started to moderate with the weather issues?

The weather issues started to moderate at the end of June. So we would hope that we would see better cost performance in the third quarter. One thing I didn't mention, Andy, is we look at a lot of metrics there, and the actual cash costs in the second quarter was less than the first quarter cost. So we did make some slight improvements in cash cost, the depreciation was just a little stronger per-unit basis.

(Operator Instructions) Chris Ellinghaus, Williams Capital.

In the gas business, have you got any indicator on latest 12-month ROE or for the quarter or anything?

They look good, Chris.

Yes. We haven't disclosed specific numbers, but obviously our earnings have improved quite a bit, so they look pretty favorable.

(Operator Instructions) Michael Worms, BMO.

Quick question, Dave, on the coal business. You were suggesting that these problems will persist into 2012. Are we looking at persisting deep into 2012 or can you give us some more color on that?

What we said, when we went in to a lot of detail in the first quarter, basically that we expected to lose money on an operating-income basis through 2011, and would be continuing to improve margins at the mine, continuing to work on cost efficiencies, continuing to work on the revenue line as well. One thing that has come up and we put it in the presentation, we had 1 contract that is underwater for us as far as off-site coal sale. We don't expect that contract to continue in the next year, so that will be hopefully a pretty significant improvement at year-end, and then I think the rest of it is going to be a gradual improvement over time. I certainly don't expect things to look like they did in 2011 in 2012. But I don't expect everything to be rosy either. It's going to be a slow gradual process. But we will make significant progress up until the end of the year, and then at end of the year with the 1 contract that's actually costing us money right now, that will be a pretty big improvement for the start of 2012.

Will that contract be renegotiated at higher rates or will that just completely go away?

If we could renegotiate at a higher rate that's acceptable to the purchaser, we would certainly be happy to do that. My anticipation today is it maybe won't be renegotiated. I think the price would have to be higher than where they could get coal from an alternative source. That's our only train-loadout customer. So to the extent we don't renegotiate that contract, we would essentially just be focusing primarily on-site coal deliveries and a few other little regional truck customers, which changes the complexion and overall cost of our mine a little bit. One of the cost drivers we mentioned in the first Quarter was the 24-hour manning of train-loadout facility, and that would obviously go away as well if we don't renew that contract.

This concludes the Q&A portion of today's call. I would now like to turn the call back over to Dave Emery for closing remarks.

Well, thank you for to everyone for your attention today and for attending our call. We are very excited about what the future holds for the Company. As I talked about earlier, we've got a lot of great growth initiatives, we're making good progress from an earnings perspective, as well. And excited about what the future holds for the Black Hills Corporation. Have a great weekend and enjoy your day, Thank you.

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