Black Hills Corp (BKH) 2015 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation fourth-quarter and full-year 2015 earnings conference call. My name is Kat 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 Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir.

Thank you, Kat. Good morning, everyone. Welcome to Black Hills Corporation's fourth-quarter and full-year 2015 earnings conference call. Leading our quarterly 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 website, 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.

Thank you, Jerome, and good morning, everyone. Thanks for participating in the call this morning. I will be following along here on the webcast presentation deck, for those of you who have it, starting on page 3. We will follow a similar agenda to previous quarters. I will give a quick update on highlights of the quarter. Rich Kinzley will cover the financial update. And then I will jump back in, for forward strategy, before we take questions from all of you.

Moving on to slide 5, fourth-quarter highlights, we had a real solid fourth-quarter, despite the fact that we had mild weather for our gas utility territories and a continued decline in crude oil and natural gas prices, which affected our oil and gas results.

During the quarter, we made great progress on several key growth initiatives, including our pending acquisition of SourceGas. Related to SourceGas, we received regulatory approvals now in three states -- Arkansas, Nebraska, and Wyoming -- and our closing will occur as soon as we receive approval in the state of Colorado. We still expect to close sometime during the first quarter.

We have also recently completed our permanent financing, both the debt and the equity needed to close the transaction, so we're ready from a finance standpoint. We still have several teams working on detailed integration activity. We expect to be fully integrated, all systems and processes, by year-end 2016, assuming we get closed by the end of the first quarter.

Moving on to slide 6, utility highlights for the quarter, Black Hills Power received final approval from the Wyoming Public Service Commission to begin construction on the first segment of our new 144-mile transmission line that will go from northeast Wyoming to Rapid City, South Dakota. We expect to start construction in February, and have that line completed and in-service by year end.

At Cheyenne Light in Wyoming, we recorded a new winter peak load of 202 megawatts on December 28; 5 megawatts higher than the previous winter peak, set the year before. At our Colorado Electric subsidiary, we received approval in October to purchase the $109 million, 60-megawatt Peak View Wind Project. That project will be built by a third-party wind developer. And we've executed a build-transfer agreement with them, and will take over as soon as the project is in service, which is expected at year end.

At Colorado Electric, we also continued construction on our new $65 million, 40-megawatt simple cycle gas turbine, which we are adding to the Pueblo Airport generating station. We expect that turbine to also be in service by year end.

Moving on to slide 7, non-regulated energy and corporate highlights for the quarter. On the non-regulated energy side, we initiated a process during the quarter to explore the sale of a minority interest in our Colorado IPP 200-megawatt combined cycle units at the Pueblo Airport generating station. That process is ongoing, and we expect to make a decision related to that potential sale in the first quarter.

We also completed our 2014-2015 Mancos Formation shale gas drilling program in the southern Piceance Basin, to prove up the extent of that resource. We drilled, completed, and tested, and now have on production nine wells. We have four additional wells that we drilled and cased. We deferred the completion activities on those four wells because we have a limited amount of gas processing capacity out of the area, and we won't need them probably until at least next year to fill the plant capacity.

Overall, the results of the drilling program exceeded our expectations, so we're quite pleased with the results there.

On the corporate side, last week our Board of Directors declared a quarterly dividend of $0.42 a share. That's equivalent to an annual dividend rate of $1.68. The increase to $0.42 represents the 46th consecutive annual increase in dividends to shareholders. During the quarter, we also entered into $400 million of interest rate swaps to mitigate interest rate risk associated with the future debt refinancing activity we expect in late 2016 and early 2017.

Moving on to slide 8, this just simply provides a reconciliation of fourth-quarter income from continuing operations, as adjusted, to fourth-quarter 2014 results. Strong performance at our electric utilities and power generation segments nearly made up for the negative weather impacts at our gas utilities and the low crude oil and natural gas prices at our oil and gas subsidiary that I mentioned earlier.

Slide 9 provides a similar reconciliation for full-year 2015 versus full-year 2014. Again, despite the challenges, we were still able to post an increase in net income, as adjusted.

Now I will turn it over to Rich Kinzley to talk about the financials for the quarter and the year. Rich?

All right. Thanks, Dave, and good morning, everyone. We are encouraged to report another year of earnings growth in 2015, driven by strong results at the electric utilities, power generation, and coal mining businesses. As Dave mentioned, overall results were tempered by unfavorable weather and low crude and natural gas prices. Our gas utilities faced warmer-than-normal weather in the winter heating months in 2015 compared to colder-than-normal weather in 2014, which contributed to a decline in year-over-year performance. And low commodity prices impacted our oil and gas business. But despite those challenges, we again delivered earnings growth in 2015.

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 better represent our ongoing performance. This slide displays the last five quarters in each of the last two years.

In each quarter of 2015, we incurred a non-cash ceiling test impairment charge at our oil and gas business, due to the continued decline of crude oil and natural gas prices throughout 2015. In the second quarter of 2015, we also recorded a non-cash impairment of an equity investment at our oil and gas business, due to low commodity prices. In the fourth quarter, we divested this equity investment and realized a small gain above the impaired book value.

We also incurred external acquisition-related expenses, like financing and other third-party costs, in the second, third, and fourth quarters of 2015 associated with the pending SourceGas acquisition. These impairments and acquisition expenses are not reflective of our ongoing performance; and, accordingly, we reflect them on an as-adjusted basis.

Our fourth-quarter as-adjusted EPS, reflective of ongoing operations, was $0.71 per share compared to $0.77 in the fourth quarter last year. Our full-year as-adjusted EPS was $2.98 for 2015 compared to $2.93 for 2014. Fourth-quarter and full-year EPS were diluted by approximately $0.04 each, due to the 6.3 million share common stock offering we completed in November to partially fund the SourceGas acquisition.

Slide 12 displays our fourth-quarter revenue and operating income. On the left side of the slide, you'll note that revenue was lower in 2015 due to reduced revenues at our gas utilities from lower pass-through gas costs during the year, given the low natural gas price environment in 2015.

On the right side of the slide, you see strong performance in the fourth quarter at our electric utilities and power generation businesses more than offset decreased performance at our gas utility, coal mining, and oil and gas businesses, resulting in a 4% increase in consolidated operating income compared to the fourth quarter in 2014.

Moving to the full year on slide 13, revenue decreased by $89 million, again due to lower pass-through gas prices in 2015 at our gas utilities. Operating income improved at our electric utilities, power generation, and coal mining businesses in 2015. These improvements were partially offset by lower earnings at our gas utilities due to warmer winter weather, and wider losses at our oil and gas business due to the lower natural gas and crude oil price environment.

In total, year-over-year operating income increased by over 7%. And excluding our oil and gas business, our core utility and utility-like businesses' operating income increased by 13%. I will touch on each business in more detail on the following slides.

Slide 14 displays our fourth-quarter and full-year income statements. Before asset impairment charges and acquisition-related expenses, we delivered operating income growth for both the fourth-quarter and full-year, despite the weather and commodity price challenges mentioned earlier.

We implemented cost management efforts early in 2015, and I'm pleased with the way the organization responded. You can see our operating expenses decreased in the fourth quarter and increased only 1.5% for the full year. Depreciation and interest expense increased as we continue to grow our asset base.

We've broken out the non-recurring impairments and external acquisition-related expenses, including the cost of the bridge financing we arranged for the pending SourceGas acquisition.

For the full year, as-adjusted EPS grew nearly 2% year-over-year, while EBITDA increased by over 7%.

Slide 15 displays our electric utilities gross margin and operating income. The electric utilities gross margin increased in the fourth quarter by $6 million over 2014, and by $49 million year-over-year. These gross margin increases resulted primarily from return on additional investments, most notably the $222 million Cheyenne Prairie generating station, which went into service October 1, 2014.

New rates associated with these investments went into effect at all three of our electric utilities in late 2014 and early 2015. Gross margin also benefited from industrial and commercial load growth and a variety of other factors, as detailed in our earnings press release distributed yesterday.

Strong cost management throughout 2015 resulted in reduced O&M in the fourth quarter of 2015 compared to 2014, and a full-year increase of only 5%, despite 12 months of the Cheyenne Prairie plant in operation during 2015 compared to three months in 2014.

The combination of gross margin improvement and strong cost management resulted in operating income increasing by $7.3 million or 19% during the fourth quarter compared to 2014, and $36.1 million or 25% for the full-year 2015 over 2014. The electric utilities had an outstanding year, driven by large capital investments to better serve our customers.

Moving to slide 16, our gas utilities gross margin as compared to 2014 decreased $3.6 million in the fourth quarter and $7.3 million for the full year, driven by 14% fewer heating degree days in 2015 compared to 2014. Both heating seasons, comprised of the first and fourth quarters, were milder in 2015 than 2014.

Strong cost management efforts at the gas utilities, with decreases in O&M for both the quarter and full year compared to 2014, partially offset the negative weather impact. Operating income declined $3 million in the fourth quarter compared to 2014, and by $4.9 million year-over-year.

Compared to normal weather, our gas utilities gross margins were negatively impacted by an estimated $4.9 million in 2015. Also in 2015, our electric utilities gross margins were negatively impacted by an estimated $3.9 million compared to normal weather. Combined, these negative weather impacts, compared to normal, impacted our EPS by approximately $0.13 in 2015.

On slide 17, you see the power generation improved operating income by $3.2 million for the fourth quarter compared to 2014 and by $5.7 million year-over-year. The main drivers in the improved operating income were an increase in megawatts delivered in 2015 due to a Wygen I outage in 2014, and a Wygen I power purchase agreement annual price increases, as well as lower maintenance expenses and general cost management during 2015.

For the full year, as-adjusted revenue was $3.5 million higher in 2015. And as-adjusted O&M, including depreciation, was $2.2 million lower.

On slide 18, our coal mining segment had a $1.2 million operating income decrease compared to the fourth quarter in 2014. For the quarter, revenue was $2.2 million lower, as tons sold decreased by 7% compared to Q4 2014, due primarily to planned outages. Further, our regulator approved pass-through mechanism, through which we sell approximately half our coal, yielded a lower price per ton in the fourth quarter due to lower mining costs.

In Q4, O&M was $1 million lower in 2015 than 2014. For the full year, coal mining operating income increased by $1.7 million.

While tons sold were 4% lower in 2015 due to planned outages, we benefited from a significant revenue per ton increase in mid-2014 on a third-party coal contract as a result of a contractually scheduled price reopener. This contract represents approximately 35% of our production, and the higher price per ton increased our revenue in 2015 by $4 million.

Keep in mind, the revenue increase from this price adjustment did not drop straight to operating income, as we pay revenue-related royalties and taxes on the increase.

On the cost side, we enjoyed continued mining efficiencies and lower fuel costs. We moved 31% more overburden in 2015, but at a decreased per-cubic-yard cost. O&M was flat from 2014 to 2015.

Moving to oil and gas on slide 19, we incurred an operating loss in the fourth quarter of $5.8 million, excluding a $71 million pre-tax ceiling test impairment charge, compared to an operating loss of $4.5 million in 2014. Fourth-quarter production increased 45% from 2014, driven by a 67% increase in natural gas sales volumes. From an average price received standpoint, including hedges, crude oil decreased by 22%, and natural gas decreased by 38%, comparing Q4 2015 to Q4 2014.

For the full year, we incurred an operating loss of $27.5 million, excluding pre-tax ceiling test impairment charges of $250 million, compared to an operating loss of $11.8 million in 2014. 2015 production of 12.9 billion cubic feet equivalent represented a 29% increase over 2014, driven by a 41% increase in natural gas sales volume, with a 10% increase in crude oil volume and a 24% decrease in NGL sales volume.

Comparing 2015 to 2014 average prices received for the full year, including hedges, natural gas prices decreased by 39%, and crude oil by 24%.

While we are pleased with the outcome of the drilling program in the Piceance Basin over the last couple years from an operational standpoint, the low commodity price environment in 2015 severely impacted financial results at our oil and gas business.

Regarding the impairments taken in each quarter of 2015, slide 20 shows the average trailing 12-month crude oil and natural gas prices, which continued to drop each quarter in 2015, driving the impairments. Given the continued low price environment for crude oil and natural gas, it's likely we will have additional non-cash impairments to our oil and gas reserves in 2016, at least in the first quarter.

However, any impairments will be much smaller than those recorded in 2015, as our full cost pool is impaired down to approximately $94 million at the end of 2015, with an additional approximate $68 million in excluded costs, which is made up of certain infrastructure assets and wells drilled but not yet completed.

The impairments taken in 2015 are driving down our depletion rate, and our current guidance estimates a depletion rate of $0.80 to $1.20 per MCFE in 2016.

It's worth noting here that we are managing our go-forward exposure in our oil and gas business by cutting CapEx, reducing the cost structure of the business, and beginning to divest non-core properties. You can see, in our press release yesterday, the trend in the fourth quarter related to reduced O&M. And as I just noted, we expect a much reduced depletion rate in 2016, given the impairments. Dave will further address our strategy around oil and gas in a few minutes.

Slide 21 shows our capitalization. At year-end, our debt to cap ratio was 57%, with a net debt to cap ratio of just over 50%, given cash on hand. In November, we received net proceeds of $536 million from the issuance of common stock and unit mandatory convertibles to partially fund the pending SourceGas acquisition, which increased our equity and debt.

In January, we issued $550 million of long-term debt to nearly complete the permanent financing required for the acquisition. We will be assuming approximately $760 million of SourceGas debt when we close the transaction. The remaining financing needs at closing, expected to be in the range of $50 million to $100 million, will be covered with our revolver. We will be levered than normal upon closing of the acquisition, but the strong cash flows and earnings from our businesses will assist us in delevering over the next couple of years.

As you know, we continue to evaluate the potential sale of a minority interest in our Colorado IPP facility, which may yield proceeds allowing us to reduce debt. And to help fund our strong future utility-focused capital program, we plan to put an at-the-market equity program in place in 2016. We will prudently issue equity through that program in 2016 and 2017. We are committed to maintaining our current solid investment grade credit ratings, and our forward-forecasted metrics support those ratings.

Slide 22 demonstrates our track record of growing operating earnings and EPS. We look forward to closing the SourceGas acquisition, and taking the next step forward in continuing to build upon our impressive track record of growing shareholder value as we serve our utility customers safely and reliably. Our strong forward utility-based capital program will drive an above-average growth profile compared to our utility peers, and the addition of SourceGas will enhance our growth prospects.

Moving to slide 23, yesterday we updated our 2016 EPS guidance to be in a range of $2.40 to $2.60. This revision updates our previous 2016 earnings guidance issued on November 23, taking into account the additional interest expense associated with our recent $550 million debt issuance.

It's important to note, the range does not include any earnings contribution from the SourceGas properties. When the SourceGas transaction closes, we will issue updated 2016 guidance and preliminary 2017 guidance, with refreshed assumptions for all our forward-looking activities.

2016 will be a busy year as we effectively manage our businesses, integrate SourceGas, and position ourselves for strong earnings growth in 2017 and beyond.

I will turn it back to Dave now for a strategy update.

All right. Thank you, Rich. Moving on to slide 25 -- we have shown you this slide for quite some time now -- but we group our strategic goals into four major categories, and really with the overall objective of being an industry leader in all we do. Those four key objectives are profitable growth, valued service, better every day, and great workplace.

In the profitable growth area, on slide 26, strong capital spending drives our earnings growth. And we forecast a total of more than $1.1 billion in capital spending for 2016 through 2018. That projected spending far exceeds our depreciation, driving the earnings growth.

It's important to note that this table on slide 26 does not include any capital related to the SourceGas acquisition. Once that acquisition is closed, we will provide some revisions to the forecasted capital spending.

On slide 27, we continue to make great progress constructing our new turbine at the Pueblo Airport Generating Station. That $65 million simple cycle gas turbine is on schedule, and we expect it to be in service by year-end 2016. To date, we have spent about $35 million of a total $65 million budget. We are projected to come in at or under budget. Construction is about 27% complete. And, notably, we've had no safety incidents to date.

On slide 28, as I mentioned earlier, we received approval from the Colorado PUC in October to purchase the new Peak View Wind Project for our Colorado Electric utility. The third-party developer expects to commence construction in the first quarter, and achieve commercial operations by year end, at which time we will take over the project. We have made almost $12 million in progress payments as of December 31.

Moving on to slide 29, as Rich mentioned, our electric utilities demonstrated solid earnings growth in 2015. And a big part of that was our industrial load growth. We've had strong industrial load growth in all three of our electric utilities during 2015, for an overall increase in industrial load of almost 15%. That growth has been from several different industrial customers. The data center load growth, particularly in Cheyenne, Wyoming, is the most notable driver of that growth.

Slide 30, another significant growth opportunity we are pursuing very actively is a utility cost of service gas supply program. We've been talking about this for well over a year now. Under a cost of service gas program, our direct investment in natural gas reserves would provide long-term price stability for our customers while also providing opportunities for increased investment in earnings for shareholders, truly a win-win scenario.

We submitted cost of service gas regulatory filings this fall in six separate states. Hearing dates have now been set in all six of those states. And we're currently in the process of evaluating producing properties and drilling prospects for inclusion in the program. That includes our Mancos Shale gas properties in the Piceance Basin in Colorado, which we are evaluating now that we've finished up our test drilling program there. We hope to finalize our cost of service gas program sometime before year-end 2016.

Moving on to slide 31, oil and gas strategy -- Rich referred to this a little bit earlier. But we previously announced our plan to transition our oil and gas business to primarily support cost of service gas within our utilities. That program will provide stable priced, low-cost deals to our utility customers. As noted earlier, we completed our 2014-2015 Mancos Shale gas drilling program, and essentially helped us prove up the magnitude of the resource we have in the southern Piceance Basin.

As Rich noted, we dramatically reduced our planned oil and gas capital spending for 2016 and 2017. Current product prices just simply don't support additional capital investment in oil and gas. And our plan for capital, going forward, is essentially putting our capital investment into a cost of service drilling program. We have reduced our staff and cut costs in order to reduce our ongoing O&M. And our professional staff at our oil and gas subsidiary is busy applying their expertise and knowledge to assist our utilities with execution of cost of service gas.

Moving on to slide 32, this slide just simply provides a well-by-well detail for our Mancos drilling program. It includes all the wells we have drilled now from 2013 through 2015. As I said earlier, overall we are very pleased with the results of the program, a little better than we expected.

Moving on to slide 33, I mentioned earlier our dividend increase. We continue to be very proud of our dividend track record, this now being our 46th consecutive year of dividend increases for shareholders. That's one of the longest strings in the utility industry, and a record we're very proud of.

Slide 34. Rich talked earlier about our solid, investment grade credit metrics. We do have a solid balance sheet and good investment grade credit ratings. Long-term, we expect the SourceGas acquisition to be credit-positive, adding substantial low-risk, predictable cash flows to our credit metrics.

On slide 35, it illustrates the focus we place every day on operational excellence and on being a great workplace. During 2015, our safety record and our electric reliability performance were both near the top of the industry. That's something we strive for in essentially all we do.

On slide 36, this is our scorecard; again, our way of holding ourselves accountable to you, our shareholders. Every year we set forth our key strategic goals and initiatives, and literally check the box on progress at we proceed throughout the year.

Slide 36 is our 2015 goals, and progress we made towards those goals.

Slide 37 is a preliminary scorecard for 2016. This includes the goal of completing the SourceGas transaction, but does not include any specific goals related to SourceGas. Once we acquire those properties, we will update this scorecard.

That concludes our remarks. We'd be happy to entertain any questions that anyone might have.

(Operator Instructions). Insoo Kim, RBC Capital Markets.

First question on the oil and gas strategy. I know you talked about the low commodity price environment, and how the potential sale or divesting of the non -- some of the assets would not result in the value that the asset that you own has. Just given the ongoing cost of service gas program, if that doesn't go through, what are your thoughts regarding that business and the timing of such a strategic decision?

Well, I think we have a have pretty high degree of confidence that we will have a cost of service gas program. The specifics of the size, and which states choose to participate, and at which levels, I think is the primary question in our mind. We think it's a program that makes tremendous sense for customers and shareholders alike. And I think we are uniquely positioned for that program because of our oil and gas expertise. Strategically, we have talked about divesting our non-core properties there.

We have made the statement that we don't intend to fire sale those, if you will. But we're taking our time and making sure we can divest of those in a way that makes sense for us, and really focusing almost all of our attention on cost of service gas. Whether that's our Mancos program in the shale gas resource we have in the southern Piceance Basin, or whether that would be reserves that we could potentially go out and purchase, or a combination of the two, that's really what we're working on right now.

We can't finalize any of those plans or decisions until we know what size program we will have, going forward, which of course is dependent on the regulatory process.

Got it. And sticking to cost of service gas, the CapEx estimates that you guys have through 2018 for that program. Is that still more of a placeholder for now, until you know what the details of the program are, and the level of investments that you'll be needing?

Essentially. The way we came up with those numbers is we assumed that we would commence a drilling program, late in 2016. And we've talked about our rough ongoing run rate for a horizontal program is around $100 million, for a rig running continuously for a full year. And so that's really where those numbers came from.

We've got some wells we have yet to complete in the Piceance, and so the 2016 number is a little lower. And then we basically assume a drilling rig year, if you will, for both 2017 and 2018, which I think is a pretty realistic assumption, assuming we get the program off the ground.

Got it. And turning to the utilities business, for the legacy Black Hills utilities, ex-SourceGas, beyond the 2016 time frame, what are some of the projects that you are looking for that could further drive rate-based growth?

Well, we've got several things we're working on. In our slide deck, we do list -- a listing of major utility projects. We break those out, back in the appendix. And there's several transmission projects, natural gas pipeline project, and other things that we're actively pursuing right now.

The other thing that we've talked about is we're short resources on the generation side, and we talked about that in our Analyst Day back in October. We are just getting started really on revisiting our resource planning for our electric utilities, and fully expect that out of that we're going to need some additional resources to meet the load growth that we are experiencing.

Got it. And just last question on -- for the electric utility -- or I guess the electric or gas utility rate load growth, how much of your load growth is dependent on oil and gas customers? I'm assuming it's relatively small, but -- and what kind of impact have you seen, if at all, due to the low commodity price environment?

Yes. Essentially, none of our load growth is dependent on oil and gas; a very, very small percent. We don't serve, on the electric side, direct oil and gas producing basins. So we get a small amount of peripheral businesses that are located near the producing basins, but it really doesn't drive a lot of growth -- a little bit of very light industrial and commercial load that we have.

We do have one oil field that we serve at Black Hills Power. Had a little bit of load growth there. It's an enhanced oil recovery project. And I would say the prices there, on a marginal cost basis, are sufficient to keep producing. And so we really haven't seen any cutbacks in production which would impact our load there. So, a pretty minimal overall exposure to oil and gas prices on the electric utility side.

Got it. Thank you very much.

(Operator Instructions). Chris Ellinghaus, Will Cap.

You quoted a $0.13 drag from weather for the year. I assume that's versus 2014.

No, that's versus normal weather, Chris.

Okay, great.

And actually a little bigger than that compared to 2014, because 2014 was a little colder than normal.

Okay. And can you give us any kind of characterization of how January went for the service areas?

Pretty close, but normal weather; maybe slightly warmer than normal, depending on the territory.

Okay. And can you give us a little more detail on where the industrial strength is coming from?

Yes, we've got several things. A lot of it is related to data center load growth and Cheyenne, Wyoming. And that's the overwhelming portion of it. Colorado, some of our industrial businesses there have been growing at a steady clip, particularly gold mining has been real strong. There's also an old munitions depot down in Pueblo where they've ramped up load as they dispose of old weapons, and expect to keep that higher load for multiple years as they go through that process.

Black Hills Power, we've just seen some of our industrial customers, whether that's crude oil refining -- I mentioned the oilfield earlier -- a combination of several of those things have helped expand load at Black Hills Power as well.

Okay. And can you give us some ideas about when your next IRPs will get filed?

Probably going to be late this year, early next year.

For all?

Yes.

Okay.

We typically do our research planning for Cheyenne Light and Black Hills Power jointly. We manage that as essentially a single load. They are interconnected systems, and we combine our resource planning efforts for those two. Colorado Electric, of course, we do separately.

Okay. And do you have any planned major outages for this year or next year?

We don't have anything that -- I don't think there's any real lengthy outages. The ones we do have planned are incorporated into our earnings guidance.

Okay. And do you have any updated thoughts on the Colorado SourceGas approval situation?

No. And I think we're pretty well positioned there. We were successful in reaching a settlement. Colorado has a process where your settlement is reviewed by an Administrative Law Judge. And then the Commission requires a little time to review the recommendation of the ALJ and issue its order. We don't foresee any real problems there. We're just going through the motions, if you will, waiting for the process to play itself out.

Okay. Thanks for the color, guys.

Andy Levi, Avon Capital Advisors.

Just two questions, maybe three. But just the first one just on the IPP sale process. Can you just give us a little more color on that? I guess it's taking a little bit longer than you thought, so just what's going on there, and when we may hear something from you on that?

I don't know if it's really taking a whole lot longer than we thought it would. We knew announcing pre-holidays is not an ideal time to get things done expeditiously. The process is going well. Obviously we have engaged an investment banker. We're going through the bidding process. We've had very strong indication of interest from multiple bidders, and we're working our way through the process. I did say earlier, we still expect to make a decision sometime before the end of the first quarter.

Okay. And any reason to think that a sale wouldn't happen, or that's probably unlikely?

I think it just really comes down to value. As I said, so far, indications have been pretty strong. When you get down into negotiating real specifics and details and selecting final bids, you never know until you're done. But we're certainly encouraged by what we see so far.

Okay. And then on the oil and gas segment, I just wanted to understand what we got left on the books. You showed $209 million of book value at the end of December. Is that correct? On page 20, I think it is.

Correct.

Okay.

Yes, so --.

Can you give us a breakdown of the $209 million?

Sure.

How much is more commodity related, and how much is, I don't know, hardware or steel in the ground type stuff?

Yes, as I pointed out in the comments earlier, $94 million of that is our full cost pool, so it's the wells that are in our pool. $68 million is in unevaluated properties, which includes some infrastructure. And then wells -- Dave mentioned that we drilled four wells in the Piceance, but didn't complete them. So they are in that pool. And then you've got the balance, which is roughly $40 million, which is the other assets of the business.

Okay. So, just to understand, the commodity exposure piece is -- what would you estimate? So if you take out the pipeline stuff, and trucks and things like that, what do you (multiple speakers)?

It's $150 million or $160 million is what's left on the books, roughly, exposed.

Okay, okay. And then I know you commented on it, but I don't think I was listening too closely. How much of that $150 million are you trying to get into rate-based gas? Or is it not that defined?

Really not defined, at this point. As Dave mentioned a bit ago, we're evaluating whether a purchase of a third-party property or our existing gas assets makes sense for that cost of service gas program, and working through that with the regulators.

Okay. What was the thing on the third-party? I'm sorry.

Well, Dave, you want to --?

Yes, one of the things we have evaluated in a way to potentially jumpstart our program, if you will, is, assuming we get approval for cost of service gas, if we could find a gas-producing property perhaps with a distressed buyer or distressed seller, we might have an opportunity to buy a property in addition to looking at some of our properties.

Primarily just the Mancos property is the one of our own that really is a good, viable, long-term gas resource. It's a least a couple trillion cubic foot resource, potentially as much as 8. And that's the one property we have we think would be a great fit for cost of service gas.

But we're also looking -- and if we can opportunistically purchase reserves from other parties, we would look to do that, to contribute to the program as well.

Okay. And then -- and I lied about the three questions. But in your guidance that you gave for 2016, the temporary guidance without SourceGas, what's the -- how much is oil and gas? What's the drag?

Well, we haven't broken out segment guidance like that yet. When we get the SourceGas deal closed, we intend to issue updated 2016 guidance and preliminary 2017 guidance. And we may provide a little more color, at that point, around -- well, certainly, we're going to provide updated assumptions on all our forward-looking activity, including oil and gas. But we may provide a little more color at that time.

The way I looked at it is -- and I think we've probably discussed this in the past -- is that you have this really good story at the utility; the IPP is good and stable, you sell a portion of that. And the coal -- [mine met] coal obviously is stable as well. So you have this really good growth story at the utilities, especially with SourceGas. And then you have this distraction of this oil and gas business, which I understand you're trying to get into rate base, for no better way to put it.

But if, for some reason, a majority of those assets or the rate-basing of gas doesn't materialize for whatever reason, what's the longer-term strategy on this? Is it just to sell it, or to continue on? Again, this is assuming that commodity prices stay where they are, which I have no idea where they are going.

But just what your thinking is on that, because you have written down the majority of it, but it is a distraction and is a drag on earnings, and then ultimately valuation. So, without that drag, let's just say it's $0.25 to $0.40. You can do the dumb math on a P/E basis, and you'll come up with a higher valuation for the stock.

Yes, I talked about this a little bit earlier. But I think we fully expect to have a cost of service gas program, going forward. The size of that and which states choose to participate, at what level of production every year, is really the question that we think it makes great sense to have a program. We think that we will be able to convince the regulators of the benefits to customers of having a program. There are tremendous benefits for customers in implementing a program. So we're pretty confident we will have a program.

As we've said, our strategy is to utilize that business to support cost of service gas. We have essentially eliminated any capital spending related to non-cost of service gas -- oil and gas investments. We have cut our staff; we have cut our ongoing operating expenses. We have the professional staff focused on cost of service gas.

And as far as the other non-core properties, we will continue to look for opportunities to divest those. We're not just throwing our hands up and dumping them. But we're going to sell them as prudent, carefully reviewed properties, and sell them to people who it make sense to sell them to, and gradually clean up the non-core properties, if you will.

As far as ongoing earnings, and the impact of ongoing earnings, when you look at the amount we impaired in 2015, the drag on earnings is going to be dramatically less in 2016 than it was in 2015. Just because we wrote off almost $250 million of our pool, and we're not spending additional capital.

So depletion will be lower. And then as we mentioned, the cost structure is lower, so the drag will not be anywhere near what it was in 2015 in 2016.

So on a clean basis, absent the write-downs, how much was the drag in 2015?

Well, the operating loss, you can see the press release, was $27 million.

Okay. So $27 million. We'll use, I don't know, 51 million shares to try and keep it where it's at. That was about $0.53 a share, or something like that, on the new share count, absent the dilution from the converts, right? About right? So, is there any type of guidance you can give us --?

We'll give updated guidance when we get the SourceGas deal closed. But, basically, the $2.40 to $2.60 incorporates the assumptions we put out in our November 23 guidance; incorporates the full drag of the equity, converts, and interest associated with the debt we just placed. And it doesn't count any income contribution from SourceGas. So it's a temporary number. Certainly, when we get SourceGas closed, I would expect 2016 to be higher than that. And then we will issue updated assumptions at that time.

Tim Winter, Gabelli and Company.

I wondered, on the 2016 guidance, I have two questions. One is, what are you guys assuming for the IPP plant? Is there any earnings in there? And then this second part is, can you give us any updated metrics on SourceGas, maybe rate-based, ROE, earnings, anything like that? Maybe just ballpark ranges.

Repeat the first part again, Tim, on the IPP? Repeat the first question on IPP?

What's the assumption in the 2016 guidance for the (multiple speakers)?

Right now, it's assumed that we own it for the full year.

Okay.

And then on the metrics for SourceGas, again, we will put some color around that when we get the deal closed.

Okay, okay. Thank you.

Tom Nowak, Advent Capital.

And I'm showing no further questions at this time.

I'd like to turn the call back to David Emery for any closing remarks.

All right. Well, thank you, everyone, for your participation this morning. We appreciate your continued interest in Black Hills. 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.