Black Hills Corporation (BKH) Q3 2016 Earnings Report, Transcript and Summary

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

Thank you, Kevin. Good morning, everyone. Welcome to Black Hills Corporation’s third quarter 2016 earnings conference call. Our materials for the third quarter including our earnings release and webcast presentation can be found on our website at, www.blackhillscorp.com. Leading our quarterly earnings discussion today are David Emery, Chairman and Chief Executive Officer; and Rich Kinzley, Senior Vice President and Chief Financial Officer. Before we begin today, I would like to note that Black Hills will be presenting at the EEI Financial Conference next week in Phoenix, Arizona. Our presentation materials and webcast information will be posted on our website, under the Investor Relations heading on Monday, November 7, after market close. 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 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.

Thank you, Jerome, and good morning, everyone. Thanks for joining us for our call this morning. We’ll follow a similar format to that that we followed in prior quarters. I’ll give an update on the third quarter and then kind of highlights. Rich Kinzley, our CFO will give the financial update. I’ll discuss forward strategy and then we’ll take questions. For those of you following along in the webcast slide deck, I will be starting on Slide 5. We had a strong third quarter. We met our earnings targets. We made great progress on the integration of SourceGas. We refinanced all of our near-term debt maturities, including those that would mature early next year and we continued construction on several of our key strategic growth projects. Highlights for the Electric Utilities, construction is essentially complete for Colorado Electric’s $109 million, 60-megawatt Peak View Wind Project. It will likely be placed in service earlier than expected, before year-end. Construction is nearing completion on Colorado Electric’s $65 million, 40-megawatt, gas-fired turbine at the Pueblo Airport Generating Station. And related to recovery of that investment, PUC hearings were held in Colorado last month and we expect new rates to be effective January 1. Our South Dakota Electric subsidiary continued construction on its $54 million electric transmission line. That line will run from northeastern Wyoming to Rapid City, South Dakota. The first segment, which is in Wyoming was energized in August and began serving customers in the second segment, which is primarily in South Dakota, is expected to be completed in the first-half of next year. Moving on Slide 6, Electric Utilities also experienced new all-time peak loads at both Colorado Electric and Wyoming Electric. That’s more than one peak load at both of those utilities this year. So demonstrates our good strong industrial load growth in both of those territories. On the Gas Utilities side, last quarter we mentioned on our call, the purchase of a 37-mile natural gas pipeline in southwest Kansas. And last quarter we also mentioned that we’re evaluating options on how best to proceed with our Utility Cost of Service Gas Program, including the possibility of filing applications for approval of specific gas properties for inclusion in the Cost of Service Gas Program. Moving on to Slide 7, continuing with the quarter highlights. Our Oil and Gas subsidiary continued its efforts to divest non-core assets, made some progress during the quarter on that, and while we’re continuing to focus our professional staff on assisting our utilities with the development of their Cost of Service Gas Program. On the corporate side, last week our Board declared a quarterly dividend of $0.42 a share. That’s equivalent to an annual rate of $1.68. During the quarter, we continued our At-the-Market equity offering program. And as I mentioned earlier, we completed several key financings. Rich will provide some detail later on those financings. Moving on to Slide 8, the integration of SourceGas continues to go as planned. And we still expect that nearly all integration activity will be completed by yearend of 2016. That represents an incredible accomplishment by our employee team. I just can’t say enough about how a great of a job they’ve done integrating very quickly and doing an excellent job making progress on integration. It’s gone extremely well. The most recent integration project that we completed, which literally was finished late Monday, was the conversion of about 260,000 customers in Colorado, Nebraska and Wyoming to our customer information, billing and payment systems; and the simultaneous deployment of electronic tablet technology to all the field technicians in those three states. Now, all of the former SourceGas customers have been converted to our unified systems platform. A few integration tasks remain, but as highlighted on Slide 9, we’re essentially 91% complete with our integration activity. And we plan to finish most of the rest of it by yearend. We will have a few things that slide into 2017. But they’ll be pretty minor, particularly from a financial impact standpoint. Moving on to Slide 10, this slide just provides a reconciliation of third quarter income from continuing operations as adjusted, compared to the third quarter of 2015. Rich will explain the variances during his review of our financial performance. Rich?

Thanks, Dave, and good morning, everyone. We are pleased with our integration activities as Dave discussed. And our ongoing operations continue to perform well. Our third quarter as adjusted EPS was $0.48 per share, compared to $0.64 per share in the third quarter last year. Q3 2016 results included results from the SourceGas acquisition, which closed on February 12. Given the seasonal nature of natural gas utilities, with typically strong results in the first and fourth quarters and softer results in the second and third quarters, we expected a drop an EPS in the second and third quarters this year compared to last year, given the addition of the SourceGas utilities. We expect to enjoy increased results in the upcoming fourth and first quarters as we benefit from the winter heating season at the SourceGas utilities. Comparing Q3 2016 to Q3 2015 at a high level, operating income increased due to the addition of SourceGas, but net income as adjusted decreased primarily due to increased interest expense associated with the additional debt from the acquisition. Increased share count from our equity issuances to help fund the acquisition also impacted quarterly results from an EPS perspective compared to 2015. I’ll detail these items in the following slides, but I’ll emphasize that Q3 results met our expectations. As I’ll note later, we’re tightening our 2016 full year guidance for as adjusted EPS to a range of $3 dollars to $3.10 per share. On Slide 12 we reconcile GAAP earnings to earnings as adjusted, a non-GAAP measure. We do this to isolate special items and communicate earnings that we believe better represent our ongoing operating performance. This slide displays the last five quarters and trailing 12 months as of September 30 for each 2016 and 2015. During each of the past six quarters we incurred non-cash impairment charges at our oil and gas business due to the continued low crude oil and natural gas prices. We also incurred acquisition related expenses in each of the past six quarters, such as advisory fees, and financing and other third-party consulting costs associated with the SourceGas acquisition and integration. These non-cash impairments and acquisition expenses are not reflective of our ongoing performance and accordingly will reflect them on an as adjusted basis. Slide 13 displays our third quarter revenue and operating income. On the left side of the slide you’ll note that Q3 2016 revenue was up 23% compared to Q3 2015 primarily from the addition of the SourceGas utilities. On the right side of the slide, you see a 24% increase in total operating income driven by an $8.9 million increase at our Gas Utilities from the addition of SourceGas, and $5.8 million improvement at oil and gas due mainly to lower operating and depletion expenses. The Electric Utilities also saw $1.5 million increase in operating income compared to last year. Our Mining and Power Generation segments were essentially flat year-over-year. The corporate segment operating loss of $3.1 million in Q3 2016, was driven by internal labor costs which continue to support our SourceGas integration efforts. I’ll discuss each business unit in further detail on the following slides. Slide 14 displays our third quarter income statement. Gross margin operating expenses in DD&A all increased comparing Q3 2016 to Q3 2015 as a result of the SourceGas acquisition. As I noted on a previous slide, operating income before special items increased 24% year-over-year. Special items include the oil and gas impairments and acquisition related costs. These items amounted to $11.9 million after tax for the quarter or $0.22 per share. Interest expense increased year-over-year related to the increased debt from the acquisition. We had a $9.1 million increase in diluted shares outstanding compared to the previous year, resulting primarily from our equity and unit mandatory issuance is in November of last year related to the acquisition. We issued 6.3 million common shares in November, and the application of the treasury stock method related to the unit mandatories added approximately 1.4 million shares to the Q3 2016 diluted share count. Additionally, since launching our At-the-Market equity offering program in March this year, we’ve issued 1.75 million shares through the end of Q3. For the quarter as adjusted EPS decrease from $0.64 last year to $0.48 this year. As I noted earlier this result met our expectations due to the seasonality of adding the SourceGas utilities. For the quarter as adjusted EBITDA increased by over $26 million. Moving to business unit results, the left side of Slide 15 displays our Electric Utilities third quarter gross margin and operating income. Comparing Q3 2016 to Q3 2015, gross margin was effectively flat driven by generation construction and TCA rider margins, and increased demand from our commercial and industrial customers, which was offset by lower residential usage. Operating income increased by $1.5 million, thanks to lower O&M partially offset by higher depreciation. O&M was $2.4 million lower in the third quarter of 2016 compared to 2015, as we had lower major maintenance expense resulting from a generation outage last year. In addition to the allocation of central service costs to corporate in 2016 related to the SourceGas integration activities. Depreciation was $1 million higher in 2016 given greater plant in service. Comparing Q3 2016 to Q3 2015 at our Gas Utilities on the right side of Slide 15, the year-over-year change is almost entirely due to the addition of SourceGas since the results from our legacy Gas Utility operations were generally flat year-over-year. O&M for the quarter was favorably impacted by the allocation of central service costs to corporate in 2016 related to SourceGas integration activities, which offset other inflationary expense increases that our legacy Gas Utilities. Comparing to normal weather at our utilities for the third quarter we were effectively flat, our Gas Utilities gross margins were negatively impacted by about $300,000, while our Electric Utility gross margins were favorably impacted by about $300,000. On Slide 16, you see the power generation operating income increased by $200,000 for the third quarter compared to 2015. The main driver was annual price increases in power purchase agreements. O&M and depreciation were comparable to 2015. Our power generation segment includes the Colorado IPP plant, which is contracted to our Colorado Electric Utility plus the Wygen I plant, which is contracted to our Wyoming Electric Utility. Colorado IPP accounts for about two-thirds of the operating income in our power gen segment. I note here that these numbers include 100% ownership of Colorado IPP. In the second quarter this year we sold a 49.9% interest in that facility. We consolidate 100% of Colorado IPPs results in our financials and then back out the 49.9% noncontrolling interest at the bottom of the income statement. Moving to the right, our Mining segment had a $400,000 increase in operating income compared to last year lower operating costs from reduced major maintenance more than offset reduced revenue, which resulted from a lower average sales price per ton, as approximately half our coal is sold on a cost-plus basis. Let’s move to Oil and Gas on Slide 17. Excluding asset impairment charges in both 2016 and 2015, we reduced the operating loss in the third quarter to $1.4 million from an operating loss of $7.2 million in Q3 2015, driven by a lower cost structure at this segment. Revenue was slightly below last year as the impact of reduced prices received more than offset a 5% increase in production. Diligent cost management for the reduction to operating expenses of $3.4 million comparing Q3 2016 to Q3 2015 and lower DD&A resulting from previous impairments with a reduction of $2.7 million comparing Q3 2016 to Q3 2015, helped to minimize the operating loss from this segment, despite continued low commodity prices received. On Slide 18, you see at the end of Q3 our net debt to capitalization ratio was 66.8%. This is generally flat from Q2, but down 240 basis points from 69.2% at the end of Q1. The reduction in the ratio was due in large part to the minority interest sale in our Colorado IPP facility in April and sales of stock through our At-the-Market equity offering program. As we move forward, we expect the ratio to continue to decline through growth in our stockholders equity from earnings. We don’t expect to add any debt in the near term, which I’ll discuss on the next slide, and our internally generated cash flows will fund CapEx and dividends for the next couple of years. Additionally, we have $299 million of unit mandatories reflected as debt on our balance sheet until those units convert to equity in the second-half of 2018. We’re committed to maintaining our solid investment-grade credit ratings and our forward forecasted metrics support those ratings. Slide 19 and 20 lay out our recent treasury activity. During the third quarter we took advantage of the low interest rate environment to refinance $1.1 billion of debt that was coming due by mid-2017. As shown on the slide, the refinancing actions include a mix of 3, 10 and 30 year notes on favorable terms. We upsized our revolver to $750 million and are evaluating the potential of starting a related commercial paper program. You see on Slide 20, that our debts termed out and we won’t need to issue or refinance any debt over the next couple years in our current business plan. We will continue to opportunistically utilize the At-the-Market equity offering program in Q4 2016 and possibly into 2017, though likely not to the extent we have in the first three quarters. We’ve been able to issue most of our planned 2016 equity through the end of the third quarter. Slide 21 demonstrates our strong track record of growing operating income and EPS. We look forward to continuing to build on our impressive track record of growing shareholder value as we serve our utility customers safely and reliably. On Slide 22, you see we’re narrowing our guidance range for 2016 earnings as adjusted to $3 to $3.10 per share from $2.90 per share to $3.10 per share. In addition we are narrowing our as adjusted EPS guidance range from 2017 to $3.45 per share to $3.65 cents per share, from $3.35 to $3.65 per share. We’re pleased with our progress to-date, integrating SourceGas, while effectively managing our businesses. An integrated and full year of SourceGas results next year positions us for strong earnings growth in 2017 and beyond. I’ll turn it back to Dave now for our strategy update.

All right. Thank you, Rich. Moving on to Slide 24, we group our strategic goals into four major categories and you’ve been seeing this from us for several years now but the overall objective is being an industry leader in nearly everything that we do. Moving on to Slide 25, over the past decade we’ve been very focused on achieving earnings growth that’s well above the industry average. And as Rich illustrated on Slide 21, we’ve achieved an average EPS growth rate in excess of 12% since 2009. Strong capital spending has been the primary driver of our growth. Now, following the acquisition of SourceGas, we plan to continue our growth emphasis, but through a slightly modified strategy at least for the next few years. We have a tremendous opportunity to grow earnings by improving the efficiency and reducing the cost of the combined Black Hills and SourceGas company. I talked earlier about our very successful integration activities in 2016 to date. Most of those have centered on the unification of systems and people. Now, we plan to turn our attention to operational practices and that represents a pretty large opportunity for us. In the capital spending area, we still plan to invest well in excess of our depreciation rate. But we will be much more focused on our capital investment decisions. This results in a slight reduction to our forecasted capital spending plans over the next couple of years. We plan to continue to prioritize safe and reliable service to our customers, but we plan to focus diligently on minimizing the regulatory lag on our investments. If you recall, when we announced the purchase to SourceGas we talked a lot about their strong organic growth opportunities. We will aggressively pursue those opportunities and others within all of our service territories. Those are opportunities such as power generation, gas pipelines, gas storage, propane and diesel conversions to natural gas, new customer growth and others. And of course we’ll continue to pursue additional small and large utility acquisitions. Moving on a Slide 26, as I mentioned earlier, strong capital spending drives our earnings growth. We still forecast more than $1.1 billion of investment for 2016 through 2018, far in excess of our depreciation, positioning us to continue our track record of strong earnings growth. Slide 27 related to the Pueblo Airport Generating Station. We’re nearly 93% complete with construction. And as I said earlier, those hearings were held last month and we expect new rates to be effective January 1. On Slide 28, also as I noted earlier, Peak View Wind Project is essentially complete. And will likely be serving customers in the near future, certainly before yearend. Slide 29, our utility Cost of Service growth opportunity, we continue to believe strongly that a utility Cost of Service Gas Program provides them long-term price stability and a reasonable expectation of long-term lower cost for customers and still provides opportunities for increased earning, truly a win-win scenario. We are evaluating options on how best to proceed with that program, including the possibility of filing new applications seeking approval of specific gas reserve properties. The timing of those applications most likely will be in the first-half of next year. Moving on to Slide 30, this slide just highlights our dividend track record. We’re very proud that we’ve been able to increase our annual dividend for shareholders for 46 consecutive years. It’s a record we’re pretty proud of, one of the longest streaks in the utility industry. Slide 31 sets forth our strong investment-grade credit ratings from all three credit rating agencies. And Slide 32 talks about operational excellence. We focus every day on operational excellence. A great example that came out here recently was updated reliability numbers. All three of our electric utilities are in the top quartile for reliability. Finally, Slide 32 is our scorecard. This is something we’ve done for quite a few years now. This is our way of holding ourselves accountable to you our shareholders. We set forth our goals at the beginning of the year and literally check the boxes as we make progress throughout the year. That concludes my remarks. We’ll be happy to open up the line to questions.

Ladies and gentlemen, we already opened the lines for your questions. [Operator Instructions] Our first question comes from Lasan Johong with Auvila.

Thank you. Good morning.

Good morning, Lasan.

David, when you - this is kind of recollecting history a little bit, so my memory might be a little fuzzy. But when Black Hills closed on the Aquila acquisition, which was the first kind of big transformative acquisition. The story behind that acquisition was that Black Hills would be able to do bolt-on acquisitions with minimal increased cost, taking advantage of existing infrastructure to provide value-add to shareholders, and largely speaking that [go been net] [ph]. So the question becomes how much more of this type of - you mentioned briefly that you would continue with - Black Hills will continue with small to large acquisitions, but how much more additional acquisitions would you be able to accomplish without having to expand your G&A and your other affiliated operations expenses dramatically?

Well, I think from - you always have to add staff when you add more work. So we would certainly add it. I think we can continue to be efficient and increasingly more efficient if we’re successful in acquiring additional utilities. The systems platform that we have in place could probably easily be doubled Lasan from our current customers count of about 1.2 million, yes. So we’ve got quite a bit of runway there. Of course, if we had additional utilities, we certainly would have to add some people commensurate with it. But our whole premise all along is that as we’ve added utilities we continue to see a more efficient cost per customer for those G&A services.

Right. Sometimes that was the objective, right, you’ve largely achieved that. So congratulations on that. But basically just to reiterate, you could double your customer service program without - and continue to get more efficient. And beyond that it starts to become a tradeoff, is that what I’m hearing?

Yes. And it depends on the system, but I would say it’s pretty safe to say that most, if not, all of our current systems platforms we could handle an almost doubling of our customer base, without having to upgrade or switch to a different system, yes.

Cost of Service Gas Program, has Black Hills decided on what assets might be going into it, whether it’s your Mancos Shale play or your third-party acquisition that you need to make in order to make that happen? And can you give us a little flavor of what you’re thinking about in terms of that new application?

Yes, we haven’t decided completely what we’re going to do as far as which properties we would propose. Certainly, the Mancos is clearly an excellent asset for Cost of Service Gas. We’ve talked about that a lot in the past. We’re really looking at long-term modeling of what that play would look like and certainly considering it as well as additional alternatives. And ideally we would like to be in a position where we could re-file in at least a few states. Sometime it’s probably going to be, like I said earlier, in the first-half of next year, probably late first quarter or thereafter.

Are you going to string it out, meaning are you going to do one and then see what the results are and do another or are you going to do a bulk? [Multiple Speakers]

Well, we probably won’t file - yes, we’re still trying to decide that. But I would say it’s somewhat unlikely we would file on all six states at the same time, but we probably won’t file one at a time either. We’re still deciding that strategy.

Okay. Last question for me, can you give me an idea of what you have in mind for the Mancos Shale, if you decide to keep that at least temporarily anyway, to keep that on the side and develop it for direct oil and gas business proposition? I mean, last time we checked, nine wells are drilled, but I haven’t heard anything more about the drilling program in the Mancos?

Yes, we really haven’t done anything since the last time we reported results kind of in yearend 2015 of our drilling program and testing program there. We’re very pleased with what we see. Gas prices currently are kind of marginal, whether we would do additional drilling there. And as we’ve said here in the last several quarters, we’re really not excited about investing dollars for just a straight up E&P investment. So our plan obviously with the Mancos, and this is part of our Cost of Service Gas decision, we think it’s an optimum property for inclusion in Cost of Service Gas. We just have to look at the economics and make sure it works. If it doesn’t work then we’ll have to reevaluate what we do with it. I don’t see us pouring hundreds of millions of dollars into a drilling program. We would probably be looking for some type of a partner or something to do something with that property. I really believe it’s an excellent property for Cost of Service Gas. And so that’s our primary focus right now.

Okay, then by insinuation or implications, does that mean that if the Cost of Service Gas Program fails to launch then you would look at divesting your oil and gas businesses altogether?

It’s possible. It’s something we would have to consider, it’s hard to say today exactly what will happen there, because that’s certainly not the outcome that we plan to achieve. But we are divesting kind of the non-core assets particularly those that aren’t excellent assets for Cost of Service Gas, and that’s been part of our focus all year, we announced a little bit of progress there, we will continue to do that. And then depending on how the Cost of Service Gas issue goes were reevaluate how best to continue with those assets.

Great. Thank you.

Thank you.

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

Hey, good morning, guys.

Good morning.

Good morning, Insoo.

Just regarding the non-core E&P asset sales, how has the valuation that you received on those properties impacted your thoughts on the potential value of the remaining assets? I know Mancos are still in play for the Cost of Service Gas potentially for the Powder River Basin, and other assets are maybe remaining any valuation that - any color on, I guess the level of valuation that you are putting on those assets?

Yes, what we talked about before, Insoo is that a lot of these non-core assets aren’t worth a whole lot. There are a lot of non-operated interests - pretty small non-operated interest in a lot of wells. So we’ve got a lot of properties there that frankly aren’t worth a whole lot and require a fair amount of administrative and technical time to administer, so that’s been our focus. I think, if you look at what we received for those, we believe we’ve got pretty good value for them in a pretty fair relative to our reserve value on the books today. We’re pretty comfortable with that. I don’t think that what we received for those properties really drives any indication of value for our remaining properties, because they’re very different. The remaining properties are more they’re large scale, large working interest where the operator things like that that just have a pretty different impact on valuation. There is also a lot more future drilling opportunities on some of those properties. So I don’t think you can drive conclusions from the non-core asset sales, as to what the value of our remaining larger assets PRB, Mancos things like that really are.

Right, I understood. And then regarding your 2017 guidance, is your decision to limit the ATM program next year is that mostly due to recent level of that in term loan issuances that you had meaning many more towards that that capital markets instead of continuing on with the ATM program going forward?

Yeah, I mean, I guess on the ATM, we’re going to just look to be opportunistic moving forward. If you look back at our 2016 guidance assumptions, we pretty much issued through the end of the third quarter, right around the midpoint of that guidance and then moving into 2017 limited is the word we put in our deck and that’s how we’re doing it, Insoo.

And that [Multiple Speakers]

Two additional comments, Insoo. One, obviously, we’re very cognizant of our credit ratings and certainly have demonstrated and our ability to access the capital markets through the ATM program, and so. I would say from a strategic perspective obviously we don’t want to issue shares if we don’t need to, but we’re more than willing to issue any of that we have to make sure we maintain our credit ratings. We feel pretty good about where we are and that’s why we say our issuances are probably going to be a little more limited this year - this coming here than they were in 2016.

I understood. And then finally, looking at the longer term beyond 2018, given the dilution you are going to get from the $300 million equity units that are converting in the fourth quarter of 2018. What are some of the offsetting drivers that could enable you to maintain the best level of earnings growth? Is it the ongoing O&M efficiency measures that you mentioned regarding SourceGas and Black Hills beyond the integration phase?

Yes, I think it’s all those things that I mentioned, the organic growth opportunities, we were really excited. They still are excited about organic growth opportunities that SourceGas brought to the table. We’ve looked that how we can transfer some of those same strategies if you will into our existing territories. We do still have electric resource plans and process. We’ve got one going on in Colorado, right now. So a combination of all of those things essentially is kind of how we plan to try to offset that dilution in 2018 and continue to show some earnings growth.

Understood. Thank you very much.

Thank you.

Our next question comes from Chris Turnure with JPMorgan.

Good morning. I was hoping we could try to walk from your original February 2016 E&P segment guidance, which is basically flat to kind of what you are giving for 2017, right now at a loss of $0.10 to $0.15. So between that time and kind of your outlook for 2017 then, and your outlook for 2017 now, it’s unchanged. But we see changes in commodity prices a lot of more kind of impairments from you as well as some asset sales. So is there something we are missing there and specifically regarding the language around 2017 guidance today. Is any component of the impairments that you’ve done this year excluded still from that 2017 guidance?

I wouldn’t say that any things excluded from what we consider in 2017. I would say just the primary bridge from one year to the next is that - product prices are certainly increased a little bit. We’ve had some impairment; we just also have some changes in all certain factors in the business. And so we expect the range just stay the same essentially. Some of that additional costs, additional time related to getting a Cost of Service Gas Program started impacts that a little, just because some of the staff time that we have planned on using for Cost of Service Gas is being - now plan to be charged to the business. So I would say no major single line items it’s just a host of lots of small things.

Okay. And how can we think about relative contribution to that loss in 2017 between your Mancos properties that you’re kind of considering core, still as you go to the Cost of Service process in the first half of next year versus the properties that you consider to be non-core?

Yes, I don’t know if I have a good ability to break out what I think those the difference in the earnings contribution of those properties would be, Chris. I think, if you look at the Mancos it’s certainly our most valuable property by a long shot that’s why - it’s a world class shale play really. So we view it is having a lot of opportunity, we are producing at relatively low level right now, and so - I don’t - and we don’t expect to change that in the interim in 2017, so I don’t expect the contribution of that change. I don’t think that there is anything that’s going to happen in 2017 with that property, even if we recommended for inclusion in Cost of Service Gas that would impact 2017 results, if we don’t file till the first half of the year it would be highly unlikely, we’d have any decisions before year end that might affect that property or anything related E&P.

But if you continue to along with some of the non-core asset sales would you expect a meaningful portion of that loss to go away, or would those be more kind of properties that are earning net income at this point?

Most of them earning a whole lot, I wouldn’t say they’re losing a lot of either, so I wouldn’t expect a huge change in the number. Not outside of the ranges that we’ve disclosed based on our plan to asset sales. If they go a little faster or little slower I don’t think it would push us outside of that range either way.

Okay. That’s helpful. The only other thing was on your synergy estimates you’ve been talking throughout the year as being able to really get done almost 100% of the work by year end 2016 and really start realizing all of those benefits in 2017. Is there anything that we should look for as we walk from 2017 into 2018 in terms of incremental synergies that just aren’t fully realized in 2017 that would help your 2018 number as well or is it really kind of come January first quarter of next year everything should be baked in on a run rate in terms of all the business lines and what you expect to see going forward for synergies?

When I talk about the earnings growth strategy, I think there’s - I talk specifically about the 2016 focus of integration is primarily unifying systems, and making the decisions on integrating offices, big picture people decisions. And that’s essentially what we’ll have done by year-end which is all the real obvious things. Now it’s really a matter of how do you focus on efficiently - more efficiently running the combined companies at the operational level, day to day level. Unifying all the - and standardizing all the day to day processes, not just the systems but all of that. And we think there’s a pretty good opportunity there. So that’s going to continue well into 2017 maybe even a little bit beyond that.

Okay, great. Thanks, Dave.

You bet.

Our next question comes from Chris Ellinghaus with Williams Capital.

Hey, guys, how are you?

Good morning.

Good morning, Chris.

Dave can you give us any additional color on - what remains in non-core E&P assets and sort of progress in that area? Are you done for the year? Just wondering if you can give us some ideas there?

No. We are absolutely not done, we’re continuing to pursue those - I would say there’s probably at least as many remaining or close to as many remaining is what we’ve sold from a value standpoint somewhere in that range, either way. And we’ve talked about this at the last couple of quarters those non-core assets aren’t going to move the needle financially one way or the other. It’s more of the impact they have on our efficiency of operations going forward. But we’re definitely still looking at some more and they’re in process whether we get them done or not remains to be seen. We’ve got multiple properties that we’re still continuing to look at for potential divestiture, some of those we’re having discussions with others about potential purchase of those assets.

Right, okay. As far as the proceeds from what was sold is - was that pretax in the press release?

Yes.

Okay. And Dave, are you suggesting that as you shift towards realizing economic synergies is opposed to the actual customer integration effort on SourceGas that those economic benefits that you can reap will continue past 2018 or past 2017 rather?

Oh, yes, yes. They’ll get smaller with time obviously, as we continue to focus our big push and what we consider to be our integration project list if you will, which is the - kind of the scorecard chart that we put in the deck here for you. That’s really again just the integration of systems, everyone on the same systems, everyone on the same benefits and wage programs those sorts of things. And that’s what we view as kind of pure integration. The next phase is really optimization of operations that’s a continual effort that never stops. But certainly 2017 is going to be the most-ripe opportunity for that. And that opportunity will continue with time, but it will continue to get smaller with time. But any of those savings that are realized, we expect those to continue on an ongoing basis other than the extent there there’s inflation in some of those other O&M expenses. The costs saving themselves and any efficiency we gain we expect to retain those either for shareholder benefit or customer benefit going forward.

Okay. And Rich, as far as the equity question goes. Will you be refining that as you give maybe your next guidance update as far as your 2017 expectations?

Yes, we may refine that further, as we move forward, but as I said earlier we bought there where we want to get to 2016 and we plan to just the opportunistic moving forward, and pretty limited in additional equity issuances.

Okay, great. Thanks for the color guys.

Thank you.

Thank you.

Our next question comes from Tim Winter with Gabelli.

Good morning, guys, and congrats on the results, more importantly the 12% growth records since 2009. But I’m wondering if I can push a little more on the 16% growth rate from midpoint of 2016 to midpoint of 2017. Would you say the bulk of it is going to come from synergies with SourceGas or rate cases? If you can just give a little more color there.

Well, it’s largely synergies, Tim, but also we’re going to pick up about 40 some days more of SourceGas. We closed February 12, so we missed a month and a half of the heating season in 2016. And we’ll pick that up in 2017. That’s a pretty good chunk of it as well.

Are there other drivers, I mean, from just the normal…

There are other smaller ones. I mean, that’s the bulk of it, but there are other smaller ones like we are going through a rate process in Colorado, so we’ll have new rates effective there January 1.

Got the Peak View Wind Project and that doesn’t drive a specific rate request. That’s handled through our energy cost adjustments in Colorado. So that will take effect here soon. So you don’t lose a couple of those projects. The electric transmission project at South Dakota Electric Utility, those few things are all included in there as well, in addition to the increase due to SourceGas, either from earnings in the winter as Rich pointed out or savings opportunities as a combined company.

Okay.

And as Dave mentioned too, during his comments, we’ve got some pretty good strong industrial growth at some of our utilities. But there is just a variety of things contributing. But the big things are the synergies, additional SourceGas heating season, and then the other things we mentioned.

Okay. Thank you.

You bet.

Our next question comes from Joe Zhou with Avon Capital Advisors.

Hi, it’s Andy Levi. How you guys doing?

Good.

Just two questions, so would another driver in 2018 possibly be, I guess, you’ll be making your filings on your - of your gas filings in various states, I guess, in the first-half of 2017, is that correct, as far as, yes, Cost to Service Gas? I’m sorry.

Yes, we hope to make that decision and have those at least some of them filed in the first-half of 2017. Unlikely we would get the decision before the end of 2017 however.

Right, but you’ll probably get by the third quarter, have an idea of whether it’s going to be successful or not, just like you did…

Yes, third or fourth quarter, yes.

Yes, I guess my point is that, as you look at the driver in 2018 and just tell me if I’m correct on this. Either you get the Cost of Service Gas or if you don’t I think like you’ve articulated before then you would exit that business if you didn’t and that could - one way or the other provide at least $0.10 to $0.15 of upside in 2018 relative to 2017 where you have $0.10 to $0.15 of drag, is that fair?

Well, I wouldn’t say it’s fair on the earnings numbers. We’re not really commenting on what that impact would be, depending on what we decide to do. As I mentioned earlier, if we’re not successful in Cost of Service Gas, we’ll have to decide specifically what we want to do with oil and gas subsidiary and the related properties. And we haven’t said specifically what we’ll do. I think it’s going to depend on circumstances when we get to that point. I don’t think - as I said earlier, that’s not our plan. Our plan is to use the expertise we have in oil and gas to develop assets for Cost of Service Gas. We’ve got an extremely well qualified technical staff that would do a great job operating a Cost of Service Gas Program for our utility and that’s really our key strategy and that’s what we’re focused on right now.

No, I understood that.

[indiscernible] and that it’s going to be a positive, right.

Right, right, it will be more than 10% to 15%, sorry, unless [ph] you get rid of the drag and then you have the earnings from that. But I guess my point is if you were not successful on that and you were not able to get that, whether you most likely exit that business and eliminate the drag? So either way, there should be some upside, whether it’s Cost of Service Gas or exiting, again assuming prices are where they are prices. Obviously, prices go up, but that’s a whole another aspect. But I think we all agree and I know we went through this on the second quarter call, that this is not core to your utility business. So if you weren’t able to put it into rate base. My understanding from the conferences in September is that you are articulating that you were potentially going to exit that business.

Yes, and as we’ve said that, that’s certainly an alternative that’s available to us.

Okay, I guess I’ll leave it at that. And then just digestion timeframe on SourceGas, how long is that?

What timeframe?

Digestion.

Digestion?

Digestion.

Yes, I mean, we talked earlier about just how long it takes to integrate. And I would say the big push is over. Now, it’s optimizing the combined operation. That probably takes the better part of another year. Just we’re a lot bigger. We need to revisit the way we do business in a lot of areas, and unify and standardize kind of those day-to-day processes in the field, not just the systems that are used for those processes, but the actual steps in the process itself. And so, that’s probably an activity that continues largely through 2017. There’ll always be some lingering improvement efforts. I mean, we’re always focused on doing a better job every day. And so that will continue. But the lion’s share, it’s going to be through 2017 and maybe into early 2018.

Okay, because I just wanted to clarify, because as you know we like the story a lot, a lot of different aspects of it. And as you went through Page 25 on the handout, the last bullet point was, continuing to pursue additional large and small utility acquisitions, which is fine. But I guess that’s more of a longer-term aspiration. Is that kind of what you’re saying through, that’s why I asked about the digestion?

I would say from an integration standpoint, by the time we get to the end of this year or at least in a decent position that we can seriously consider opportunities as they arrive. The small things we will look at every day. The big ones, we’re getting to the point where we would be able to tackle one again. We’re awful close to being there. If you went out, and we don’t have anything available to us today, but certainly there’s a lot of consolidation going on in our space. If we were to look at one even today, it still takes almost 12 months for anything to happen. So we’re already in a position where we could at least seriously consider things, if they’re available to us.

As is your balance sheet?

Well, we certainly wouldn’t have the opportunity to do like we did with SourceGas, where we essentially levered up to buy it. So in the near-term, we would probably be a little less competitive in a very competitive process, just because we don’t have the ability to use debt to the extent we did with SourceGas. That will change every day. As Rich said, we’re emphasizing kind of de-levering balance sheet here, primarily through earnings and equity growth rather than debt reduction. And our position there will get better every day.

Right, but it’s really not till 80 in that the balance sheet really…

But that’s when the - when the convert converts that’s a big trigger, okay, yeah.

Right, right, right, okay. Thank you very much guys. See you in a couple of days.

Thank you.

Our next question comes from Lasan Johong with Auvila.

Well, thanks for taking my follow-up questions. A quick follow up on the Mancos Shale play. What kind of reserves per well are you kind of estimating for Mancos Shale?

I mean, we have had numbers in our prior decks, Lasan, and they’re laid out in there. I mean, most of the average numbers are in that 8 to 10 Bs a well kind of range. You can look back in some of our previous IR materials and we’ve got specific slides that lay that up.

No, no, no. I know what those are. I just was wondering if you had an updated number, because you…

We haven’t done any additional drilling. Yes, we haven’t done any additional drilling that would change our previous estimates materially. The one statement that I will make about the Mancos, and this is true, essentially any drilling play is, as you continue to drill and you drill regularly in one of these plays you continue to do better on productivity and better on cost over time, in general. I mean, that’s kind of the norm for early stage plays, especially shale plays, where it’s more of a repeatability gas manufacturing process, if you will. So we would expect hopefully that there will be some modest improvement in both the cost and the reserve numbers over time. But we haven’t revised anything meaningfully from the numbers that we put out in detail before.

Understood.

And the wells we drilled and they’re producing continue to produce as we…

Yes, as normally [ph] as expected, right.

Perfect. And 8 to 10 Bs, that’s just well for shale well. But anyway, last question I have is, there is going to - has to be a delay between when you get final approval for your Cost of Service Gas Program and when you actually provide the service, correct? Whether it’s because you have to ramp up your drilling on the Mancos or whether you have to go out and purchase something temporarily to fill that need until your Mancos Shale play comes up. And I was just wondering, what kind of lag there will be between final approval and actual service.

Well, it really depends on what properties we pursue and how we choose to pursue them. If we put in a property that’s already producing, we’re probably not going to put something in that fills the full requirement of the amount of gas we’re proposing that comes from Cost of Service Gas. But we might have something available right away. So you will at least [Multiple Speakers].

So you need to get a [Multiple Speakers].

…gas customers immediately. And then, that would ramp up as you ramp up your drilling program or whatever. If you just buy properties and put it in there, of course, it’s more of a stair-step type function. Put in a piece initially and then buy another property and it jumps up a little bit. Our preference is probably a little more heavily weighted towards drilling wisdom acquisitions to kind of fill in the gaps.

Perfect. And last question, arguably by 2018, but certainly by 2019, you’re going to be in a pretty strong positive free cash flow position, where now you’ve got too much cash on your hand so to speak. How do you - I mean, are you going to do another big acquisition at that point, as Andy kind of indicated, or are you just looking to at this point in time just improve your credit rating and get to maybe a A or AA, but [Multiple Speakers].

And we’re not interested in - and we’re not interested in that. We’ve said all along our credit rating targets kind of be a mid-BBB. And that’s something that we’re happy with. We think it’s kind of the optimum place for us to be. One of the things, when I talked about right now, our focus on kind of optimizing capital spending and really essentially reducing regulatory lag in the next couple years is really what we’re doing. Making sure we maintain the safety and reliability of our system. But being careful about what we spend our money on. There are projects that are longer-term reliability projects, longer-term projects that are going to benefit our customers pretty strongly. That will be available to us in those years. And so, I don’t think you’re going to see a situation where our capital spending drops off. And in fact, it’s probably likely to get even stronger in those out years beyond the ones we disclose, just because we’re really focusing our spending now. And there will be as we start getting into a little more maturity with operating the combined utilities, there will be investment opportunities down the road that we don’t have in our forecast today. We’re pretty comfortable with that.

Perfect. Thank you very much.

Thank you.

And I’m not showing any further questions at this time. I’d like to turn the call back to David Emery for closing remarks.

All right. Well, thanks for your time and attention this morning. We appreciate your interest in Black Hills. Have a great rest of your day. Thank you.