Black Hills Corp (BKH) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation fourth-quarter and full-year 2016 earnings conference call. My name is Liz, and I will be your coordinator for today.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to Mr. Dave Soderquist, Investor Relations Analyst of Black Hills Corporation. Please proceed, sir.

Thank you, Liz. Good morning, everyone, and welcome to Black Hills Corporation's fourth-quarter and full-year 2016 earnings conference call. Our materials for the fourth-quarter and full-year 2016, including our earnings release and webcast presentation, can be found on our website at www.blackhillscorp.com.

Leading our earnings discussion today are David Emery, Chairman and Chief Executive Officer; and Rich Kinzley, Senior Vice President and Chief Financial Officer. During our earnings discussion today, some of the comments we make may contain forward-looking statements as defined by the Securities and Exchange Commission, and there are a number of uncertainties inherent in such comments.

Although we believe that our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. We direct you to our earnings release, slide 2 of the investor presentation on our 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.

All right. Thank you, Dave. Good morning, everyone. For those of you following along on the webcast presentation deck, I'll be starting on slide 3.

This morning we'll follow a similar format to that we've followed in previous quarters. I'll give a quick update on the quarter, our CFO, Rich Kinzley, will provide some financial updates related to the quarter and year end, and then I'll talk about forward strategy, and then after that we'll take questions.

Moving on to slide 5. We had a great fourth quarter and really capped off an excellent 2016. During the quarter we completed two key strategic power generation projects. We essentially completed the integration of our SourceGas acquisition and posted strong quarterly earnings results.

On the utilities side several highlights for the quarter are Colorado Electric Utility finalized the purchase of $109 million, 60-megawatt Peak View Wind Project. We also completed the $63 million, 40-megawatt natural gas-fired turbine at our Pueblo Airport Generating Station.

Related to that turbine, you may recall on May 3, we filed a request with the Colorado PUC to increase annual revenues $8.5 million. On December 16, the PUC granted $1.2 million of new revenue beginning in 2017, and that's in addition to the $5.9 million in recurring annual revenue from our construction financing rider, which had been previously approved by the PUC.

We were very disappointed in the PUC's decision. It was contrary to both state law and prior Colorado PUC precedent, and we also believe that Commissioner Koncilja acted with bias during the proceeding. So on January 17, we filed for reconsideration of the decision and also filed to recuse Commissioner Koncilja from the proceeding.

Also during the fourth quarter, our South Dakota Electric Utility continued construction on our $54 million electric transmission line from Northeast Wyoming to Rapid City, South Dakota. The final segment, which is in South Dakota, is under construction and will be completed in the first half of this year.

Also during the quarter, our Wyoming Electric Utility set a new winter peak load of 230 megawatts. That surpassed the previous winter peak of the prior-year by almost 14%.

Moving on to slide 6, continuing with fourth-quarter highlights, our oil and gas subsidiary continued its efforts during the quarter to divest non-core assets while focusing its professional staff on assisting our utilities with their Cost to Service Gas program.

On a corporate side, earlier this week we announced that Bob Myers, our senior vice president and chief human resources officer, will be retiring April 1, after nine years of service. He will be succeeded by Jennifer Landis, who is previously our vice president of human resources. She has been with the Company 15 years.

Bob has played a key role in the growth and success of the Company over the last nine years and he will be missed.

Last week our board declared a quarterly dividend of $0.445 per share, equivalent to an annual dividend rate of $1.78 per share, which is an increase of $0.10 per share. This also represents the Company's 47th consecutive annual increase in dividends.

During the fourth quarter, we announced two changes to our board membership. Effective January 1, Bob Otto joined the board, and sadly, Gary Pechota, who has been on the board since 2007, passed away unexpectedly on December 15.

In late December we initiated a commercial paper program under our revolving credit facility, and during 2016 we issued a total of nearly 2 million shares under our at-the-market equity offering program for total net proceeds during the year of just under $120 million.

Moving on to slide 7, the integration of SourceGas is essentially complete, with only a couple of minor items remaining. So this will be the last time we show our integration progress report. This shows that, in aggregate, we were 95% complete as of year-end. We've made additional progress since then, and like I said, we're essentially complete.

Slide 8 provides a reconciliation of fourth-quarter income from continuing operations as adjusted, compared to the fourth-quarter of 2015. Rich will discuss the specific variances during his review of our financial performance, but the most obvious variance is the increase in income from our gas utilities, primarily driven by the addition of SourceGas.

Slide 9 provides a similar reconciliation comparing net income from continuing operations as adjusted from 2016 versus 2015. As you can see, we achieved a solid increase in income year over year.

With that, I will turn it over to Rich for the financial update. Rich?

Great. Thank you, Dave, and good morning, everyone. As Dave, noted we've completed the heavy lifting around integrating the SourceGas utilities, and we're proud to celebrate our performance in 2016. In addition to the substantial growth in our gas utilities from the SourceGas acquisition, we are pleased to report another year of strong operating performance at our other core business segments.

On slide 11 we reconcile GAAP earnings to earnings as adjusted on non-GAAP measure. We do this to isolate special items and communicate earnings that we believe better represent our ongoing performance. This slide illustrates are strong earnings growth for both the quarter and for the full-year.

For the fourth quarter in particular, earnings for 2016 were far in excess of 2015, thanks largely to the earnings contribution from the acquired SourceGas utilities during the winter heating season. Specifically as adjusted EPS for the fourth quarter was $1.07 per share compared to $0.71 per share in the fourth quarter last year. As I mentioned on prior calls, we have a seasonal earnings stream with the greatest level of earnings in the first and fourth quarters. As adjusted EPS grew for the full-year 2016 to $3.19 from $2.98 in 2015 representing 7% year-over-year growth.

As detailed on this slide, we experienced special items not reflective of our ongoing performance in each quarter of 2016 and in 2015. The first is non-cash impairments at our oil and gas business due to continued low commodity prices.

The second is acquisition-related expenses such as advisory fees, financing, and other third-party costs associated with the SourceGas acquisition and integration. While we may have continued integration costs in 2017, we expect them to be minimal given the substantial completion of most major integration activities in 2016.

Slide 12 displays our fourth-quarter revenue and operating income. On the left side of the slide, you'll note that 2016 revenues for Q4 exceeded those in 2015 by 46%, mainly due to the addition of the SourceGas utilities. On the right side of the slide, you see either flat or slightly improved operating performance in the fourth quarter at our electric utilities, mining, and power generation businesses.

Operating income increased substantially for the gas utilities given the addition of the SourceGas properties, and the oil and gas business had a good fourth quarter compared to last year because of cost improvements that we've made there.

Moving to the full year on slide 13, revenue increased by nearly $270 million, again thanks primarily to the addition of SourceGas. Operating income improved at each business segment in 2016, other than a small decrease at our mining business driven by an extended power plant outage in Q2. These net improvements at the operating segments were partially offset by increased losses recorded at the corporate segment related to internal labor charges for acquisition and integration work during 2016.

In total, year over year as adjusted operating income increased by approximately 32%, the vast majority of which was attributable to the addition of SourceGas. I'll discuss each business unit 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 strong operating results for both the fourth quarter and the full year. In addition to the large gross margin contribution from the addition of the SourceGas properties, the positive results were largely driven by the Organization's ability to swiftly and effectively complete the SourceGas integration activities in 2016, allowing us to realize merger-related cost efficiencies sooner than expected.

Our legacy utility businesses also demonstrated growth in 2016. Depreciation increased due to the acquisition and from continued growth and rate base at our legacy businesses. The impact of the combination of these items grew operating income before special items by 32% from $283 million in 2015, to $373 million in 2016, as you saw on the previous slide.

I'll also note 2016 only included 10.5 months of SourceGas results, as we closed the acquisition in mid-February. We look forward to adding another month and a half of the heating season from these gas utilities in 2017.

Moving down the income statement, we've broken out the nonrecurring impairments and external acquisition-related expenses which I described earlier. Interest expense increased as we added debt to fund the acquisition. We had a low effective tax rate for the quarter and the full year. Income taxes for the fourth quarter actually resulted in a net benefit, due primarily to production tax credits associated with the Peak View Wind Farm coming online during the quarter and favorable flow-through tax adjustments that were consistent with prescribed regulatory treatment.

These items amounted to a Q4 tax benefit of approximately $3.1 million. Our full-year effective tax rate came in at 11.3%. In addition to the fourth quarter items I just mentioned, in the first quarter we reached agreement with the IRS on disputed items from tax years 2007 through 2009, resulting in tax benefits of approximately $5.1 million.

Also in the first quarter, we changed our methodology for tax depletion at our oil and gas subsidiary, resulting in a tax benefit for this change in estimate of approximately $5.8 million related to tax years 2007 through 2014. In total these tax items amounted to approximately $0.06 of EPS benefit in Q4 and approximately $0.26 for the full year.

You see our weighted average share count increased compared to 2015 for both the quarter and full-year due to the November 2015 issuance of equity to fund the acquisition and from our at-the-market equity offering program whereby we issued just sort of 2 million shares in 2016. Overall for the full year, as adjusted EPS grew 7% year over year, while EBITDA increased by 29%.

Slide 15 displays our electric utilities gross margin and operating income. Electric utilities gross margin increased in the fourth quarter by $6 million over 2015 and by $4.9 million year over year. These gross margin increases resulted primarily from rider returns on investments in generation, vegetation management, and transmission. A number of other offsetting items related to our electric utilities gross margin are detailed in yesterday's press release.

Strong cost management at the electric utilities and lower allocated corporate O&M resulting from the integration of SourceGas provided reduced O&M year over year. Operating income increased by $1.3 million or approximately 3% for the fourth quarter compared to 2015 and by $3.9 million or 2.2% for the full-year compared to 2015. The electric utilities had another solid year.

Moving to slide 16, improved resulted at our gas utilities for the fourth quarter and full year are explained almost entirely by the addition of SourceGas. Our legacy gas operations, though, also demonstrated improved operating income with a 5% growth rate year over year. Our legacy gas utility operations benefited from gross margin growth from our smaller acquisition in Wyoming in mid-2015.

O&M for the year at our legacy gas utilities 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 at our legacy businesses. The key takeaway here though, is the earnings power the addition of SourceGas utilities brings to Black Hills, which is demonstrated by a full fourth quarter of results from SourceGas in 2016.

Comparing to normal weather at our utilities for the full year, our gas utility gross margins were negatively impacted by an estimated $11 million, and our electric utility gross margins were unfavorably impacted by an estimated $2 million.

On slide 17 you will see power generation operating income was effectively flat for the fourth quarter compared to 2015 and increased by $500,000 year over year. The power gen business unit continues to realize strong contract availability with its units and continued its cash flow contributions to Black Hills. Our power gen 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 approximate 60% of the operating income in our power gen segment. I'll note here these numbers include 100% ownership of Colorado IPP on slide 17. In the second quarter of this year we sold 49.9% interest in the Colorado IPP. Under GAAP, we consolidate 100% of Colorado IPPs results in our financial statements, and then we back out the 49.9% non-controlling interest at the bottom of the income statement.

On slide 18, our mining segment had an $800,000 operating income increase compared to the fourth-quarter in 2015. For the quarter, revenue was $700,000 higher, as tons sold increased by 9% compared to Q4 2015, due primarily to a power plant outage in last year's Q4.

For the full, year mining operating income decreased by $2.2 million. The primary driver here was an extended 11-week outage at the Wyodak plant in the second quarter of 2016. We sell over one-third of our coal annually to this plant.

Revenue was $4.8 million lower, as tons sold decreased 8% compared to 2015. Keep in mind the revenue decrease from this impact does not drop straight to operating income, as revenue-related royalties and taxes decrease accordingly.

On the costs side, we enjoyed continue mining efficiencies and lower fuel costs. We moved 30% more overburden in 2016 but at a decreased per-cubic-yard cost.

O&M was 2.5 million lower in 2016 than 2015. Our mine continues to perform at a high level, with sales almost entirely to on-site [mine melt] plants and roughly half our sales based on a cost-plus mechanism.

Moving to oil and gas on slide 19, excluding impairment charges in 2016 and 2015, we incurred an operating loss in the fourth quarter of $1.7 million, an improvement compared to the operating loss of $5.8 million in Q4 2015. For the full year, excluding impairment charges both years, we incurred an operating loss of $12 million this year compared to an operating loss of $27.5 million in 2015. The improvement for both the quarter and full year was primarily driven by aggressive cost management and reduced depletion due to prior-period impairments.

In 2016 we received proceeds amounting to approximately $11 million related to divestitures of non-core properties, and as Dave mentioned, we're working on focusing that business on supporting our cost of service gas initiative. Given impairments taken over the past two years, due to continued low commodity price environment, the remaining book value of our oil and gas business is approximately $84 million at the end of 2016.

Slide 20 shows our capitalization. At year end, our net debt-to-cap ratio was just above 67%. This is generally flat from Q3 but down over 200 basis points from greater than 69% at the end of Q1. 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 significant debt near-term, which I will talk about on the next slide, and our internally-generated cash flows will fund our CapEx and dividends for the next couple of years.

Additional we have $299 million of unit mandatory convertibles reflected as debt on our balance sheet until the units convert to equity in the second half of 2018. We're committed to maintaining our current solid investment grade credit ratings and our forward forecasted metrics to support those ratings.

Slide 21 demonstrates that we are in good shape relative to upcoming debt maturities. We executed significant financing activities in 2016, as we financed the SourceGas acquisition and cleaned up debt we assumed through that acquisition. The orange bars on the slide indicate debt we placed in 2016 at favorable terms.

We also instituted an at-the-market equity program in 2016 that Dave mentioned earlier, and we can utilize that further in 2017 if needed. We're not likely, however, to use the program anywhere near to the extent we did in 2016, where we raised $119 million.

We also implemented a commercial paper program in late 2016. Dave mentioned that earlier, too, and that's aimed at minimizing short-term borrowing costs.

Slide 22 demonstrates our track record of growing operating earnings and EPS. The midpoint of our 2017 EPS guidance exhibits a full year of earnings contribution from the fully integrated SourceGas as we take the next steps forward in continuing to build on our impressive track record of growing shareholder value as we serve our utility customers safely and reliably.

On slide 23 we are reaffirming our 2017 earnings guidance of $3.45 to $3.65 per share. The major assumptions driving this range are detailed on this slide. We're pleased with our progress to date of integrating SourceGas while effectively managing all our businesses. An integrated and full year of SourceGas results positions us for strong earnings growth in 2017 and beyond.

With those comments, I will turn it back to Dave.

All right. Thank you, Rich. Moving on to slide 25, we group our long-term strategic goals into four major categories, with the overall objective of being an industry leader in all we do.

From slide 26, as discussed in a little more detail on the third-quarter call, we have a tremendous opportunity to provide earnings growth by improving the efficiency and reducing the costs of the combined Black Hills and SourceGas Company, while we focus our capital spending to reduce or eliminate regulatory lag to the extent possible.

Slide 27. Strong capital spending has and will continue to drive our earnings growth. Even with an increased focus on reducing regulatory lag, we still expect to spent about $1 billion from 2017 to 2019, continuing to spend far in excess of depreciation.

Slide 28 provides more detail on our recently completed Pueblo Airport Generating Station 40-megawatt turbine. That project was placed in service on schedule and slightly under budget on December 29.

Moving on to slide 29, also as noted earlier, our $109 million Peak View Wind Project was placed in service in early November, nearly two months ahead of schedule. It will help us comply with Colorado's renewable energy standard.

Slide 30. In the last several weeks, we made significant progress on our Colorado Electric resource plan. We entered into a settlement agreement specifying the addition of approximately 60 megawatts of renewable energy to be in service by 2019. That will help us continue to comply with the renewable energy standard in the state of Colorado.

On January 17 a Colorado administrative law judge issued an order approving the settlement agreement. That will become effective as of February 6. We now intend to issue an RFP seeking proposals for 60 megawatts of renewable energy. Hopefully later in the year we will be able to recommend to the Commission specifically which projects that 60 megawatts would entail.

On slide 31, we continue to believe strongly that a utility cost of service gas program will provide long-term price stability and a reasonable expectation of long-term lower costs for customers while providing opportunities for increased earnings. That's truly a win-win. We're in the process of evaluating options still on how best to proceed with cost of service gas, including the probability of filing new applications for specific gas reserves. If we file those applications, it'll likely be in the first half of 2017.

Moving onto slide 32, we're extremely proud of our dividend track record, having increased dividends for shareholders for a total now of 47 consecutive years. We took a good step this year by increasing the dividend at an equivalent annual rate of $0.10. Our track record is very important to us, so increases are something that we take seriously, do it in a measured, cautious approach, but we're very proud of our track record.

Slide 33 outlines our current investment-grade credit ratings with all three credit rating agencies.

And on slide 34, we focus every day on operational excellence. An example here on this slide is that all three of our electric utilities are in the top quartile for electric reliability nationwide. That's a statistic we are very proud of.

Finally, on slide 35, this is our scorecard. It's something we do every year to hold ourselves accountable to you, our shareholders. Slide 35 is a scorecard for 2016. It demonstrates the progress we made toward our strategic goals during the year, and then slide 36 is our 2017 scorecard. A few of those goals are carryovers from 2016. We've also added some new ones for this year as well.

That concludes my remarks. We'd now be happy to open it up to questions.

(Operator Instructions)

Michael Weinstein, Credit Suisse

Hello. Good morning.

Good morning, Mike.

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

The settlement was just part of an ongoing process there. We approached this one very similar to the way we approached our Peak View Project. There is no specification on specifically which resources will be implemented and whether those will be Company-owned or whether those will be third-party resources.

So the specifics of that really won't occur until after we go out, issue the RFP, get the result, analyze the results, then we'll go back to the Commission with a specific recommendation for the resources that we intend to utilize -- that we recommend utilizing. If those are Company-owned, obviously that will have an implication related to how the costs are going to be recovered there. If they're just simply power purchase agreements, obviously that will be different, but the Commission then will have to approve the resulting resource at that time.

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

I don't think the settlement really addresses anything related to cost recovery. Obviously we are concerned about cost recovery. I mentioned out disappointment in the case related to the turbine.

That being said, if you look at the Peak View Wind Project, that was recovered including our return through a series of riders. That was a reasonable mechanism with which to make a good return on that investment.

We are cautious about making additional investments in the state. We're anxious to see how the Commission now moves forward with two new members, and we'll be watching that as we analyze the RFP results and making the decision whether or not we want to invest additional capital there. We certainly would like to, and we hope that we could get comfortable with doing so.

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

The timing is going to be the issue there, Mike. I think we've been relatively clear that we don't intend to stay in what I would call the traditional E&P business. As we've continued to migrate the corporation more and more towards being utility-driven, which from our perspective we've said we've largely completed that journey, we believe we've got some expertise at some properties in E&P that would be extremely good assets to serve customer gas needs for years to come. Very cost-effective assets.

If we go through the process, and the various commissions disagree with that, then we will have a decision to make on what to do with those E&P assets. I don't think we intend to revisit our decision on the E&P business. We've kind of made the decision strategically that we're phasing out of the traditional E&P investment methodology and really looking to move on to something else that integrates vertically with our utilities.

So if it's not successful, obviously we have a choice to make on the best way to continue to transition out of E&P. But I don't think it would change our decision. It might just affect timing and the way we go about it.

Got it. That's very helpful. Thank you very much.

Thanks, Mike.

Chris Ellinghaus, Williams Capital

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

I would say we did learn something. It's an interesting process. Before we filed for approval last time, we had 30-plus meetings with various regulators, commission staff, consumer advocates, and everything else to really map out the strategy we took last time.

Several of those folks suggested that it would be better for us to pursue that in two pieces: the first approval basically setting the regulatory construct for the program -- the rules of the road, if you will -- and then the second approval phase being bringing in a specific property. In reality what happened when we filed for that it was very difficult for the staffs to get their arms around making a recommendation without specific numbers. And that's really where we kind of got sidetracked the first time.

We did answer 1000-plus discovery questions in the various states. I think we learned a lot about what questions and concerns that the staffs and consumer advocates had related to a cost of service gas program, and that is certainly helping us as we rethink how we would reapply.

Certainly I don't think we would reapply without including a specific property. I think that's going to be necessary for them to really get their arms around true customer impact. And then the other thing I think going through the process we've learned that it's probably really important to make sure they understand what the program is. And that is, we are recommending that cost of service gas be part of a gas procurement portfolio for customers. We sincerely believe that over the long term it will provide significant benefits to customers.

We're making sure that we have a good plan in place. Making sure that when we do propose the program again, assuming we do that, that we've addressed the majority of the concerns that were expressed in the first round and provide the specificity, if you will, that I think the staffs need in order to recommend the program to the commissioners.

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

It's not terribly common, obviously. We just felt like it was absolutely necessary to ask for it. We did not feel that we were getting a fair shake in any way, shape, or form, unfortunately, and felt like we really had no other choice. It's not something we really preferred to do. In fact, we would avoid it at all costs, pretty much, but just felt like we didn't have any choice.

The process is -- and I don't know the exact dates, but the commissioner has the ability to voluntarily recuse herself. If she does not, we could ask the other commissioners to do that and vote to do that instead. We'll just have to play out that time frame. That will unfold here in the next week to two weeks, I believe, Chris.

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

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

Okay. Thank you for the color, guys.

Thank you, Chris.

Chris Turnure, JPMorgan

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

It's certainly an option. Until we file, I would say we don't preclude any options.

I would say it's a somewhat unlikely one. We believe strongly in the program. We would like to file. We want to make sure that we have something that looks good to regulators and staffs, and we are working on how best to package that up now and how to really make it make good sense for customers, which we believe we can do.

So I would say while it's a possibility, it's a somewhat unlikely one.

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

As you said, that's a very difficult question to answer, Chris. It depends on what the tax reform looks like. There's been a lot of discussion about deductibility of interest and expensing of capital and different things. The way those who be handled might have an impact on how urgent the Commission would be in wanting to call us in and whether -- and the normalization rules, of course, associated with how that happens would impact, I guess, the sense of urgency on the part of the commissions on whether they really feel like they need to call us in right away or not.

It's been 30 years since this has happened. The last time you saw quite a few proceedings where companies were called in for rate reviews. Some of those were related really only to dealing with the tax reform. Some were flew blown rate cases.

It's really difficult to speculate what we think would happen there until we know what the tax reform actually looks like. And as Rich said, we're engaged with EEI and AGA and others, --US Chamber and others on what the tax reform is going to look like, and we will continue to stay very engaged in that. Obviously we know what would be good for customers and what would not. But until we see some more details out of Washington, it's very difficult to guess what's going to happen.

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

No, we have not. In an ideal world of there was major tax reform, we would hope we could confine the regulatory process to dealing with the tax changes and not full-blown rate cases in every jurisdiction. But we really have no idea what's going to happen.

Okay. Great. Thank you, Dave.

Insoo Kim, RBC Capital Markets

On the 2017 guidance, the $3.55 midpoint, do you guys embed any more type of one time-ish tax benefits that you're expecting for the year, or could we look at the $3.55 as kind of the new base level to forecast future earnings growth power?

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

Understood. And then with the recent 6% dividend increase, which was definitely higher than your previous years' increases, the 2017 payout is about 50% based on the midpoint of the guidance. Could you give a little more color on the timing of doing the 6% increase and what that tells about your earnings power going forward and where you'll ultimately want the payout ratio to be in relation to that?

When we talk about a 50% to 60% payout ratio, we're going to continue to target that. Obviously we're at the low end of that. I think we are balancing, Insoo -- we're confident in our earnings growth capabilities. We talk about that, but were in the near-term we're balancing de-levering the balance sheet, earnings growth opportunities, CapEx opportunities, and then the dividend growth. So it's just that balancing act.

Our 47-year track record is very important to us. It's something we want to continue, so, and I mentioned this earlier, we do take a cautious, measured approach to how we look at dividend increases. We want to be comfortable that we can continue to increase dividends at a reasonable rate.

With that being said, we did increase it a little larger this year, and I think a lot of that is one, to get towards the bottom end of our targeted payout ratio, but two, is really in recognition of that continued change in the complexion of the Company. The addition of a large section of essentially gas LDC businesses, which are very low-risk and strong cash flow businesses, improves our ability to continue to pay dividend and gave us more confidence to go with a larger than normal increase this year.

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

We are not able to quantify them, but we have teams working in a lot of things. Just to give you kind of a flavor for what those are, we've purchased numerous utilities over the years. And we have made a big deal about how quickly we integrate those onto consistent platforms: software, hardware, et cetera.

There's still a lot of different day-to-day practices being conducted out in our various field operations. So one of the things we're doing is we've got a group of teams working on specific issues. For example, how do you hook up a new customer? What are the specific steps that a field technician takes in both our gas utilities and our electric utilities? To the extent we can streamline that, make it more efficient, everyone uses the same process, it's going to make all of our technicians more efficient.

We've also continued to automate that whole process through what we call our Click iPad field technology. That's part of the process, as well, is continuing to refine the software and the steps associated with the actual physical steps that are taken in the field. So that's one example, but we have quite a few that we're looking at. Haven't reached the point where we would quantify those yet and may not talk a lot specifically about individual projects, but I think where you're really going to see it is in our overall O&M and earnings numbers going forward.

Our goal is to continue to push through those as quickly as we can. One of the things we saw if you go all the way back to 2008 with our Aquila acquisition, after we got everyone unified on common software platforms, we saw a couple-year period where we continued to get more and more efficient in our operations, whether that was at the corporate level or at the field level. We know we have the ability to do that again maybe even to a greater extent than we did with Aquila. The difference here is that we're pushing to make it happen rather than let it happen, if you will. We've proven to ourself we can do it, so let's do it more quickly. So that's what we're doing right now.

Got it. Thank you very much.

You bet. Thank you.

Brian Chin, Bank of America Merrill Lynch

Good morning. I noticed in your prepared remarks you didn't talk about the idea of a third party coming in on your gas reserve side. Was there any change in intent or thought behind that?

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

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

I don't think it's shifted much. What I would say is that if you're working with a partner, we want to allow sufficient time for that relationship to come together. And hopefully that can happen sometime here in the near future. And then obviously how we go about presenting our case to the regulators, and which specific states do we want to file in.

We are still working on that and still doing some analysis and basically how to present this in a way that staffs and regulators can get their arms around in a process that they're used to, if you will. So I would say nothing's really changed there. The timetable is a little slower when you entertain a partner than it is when you go it alone, but we definitely feel like if that takes extra time, it's more than worth it.

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

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

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

Thank you very much.

Michael Worms, BMO Capital Markets

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

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

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

You know I don't think we need one. I think it would be very beneficial to have one. One of the assets obviously that we are considering using for cost of service gas is our [Piceance] Basin property. When you do an affiliate transaction in a regulated utility model, that transaction is always subject to a pretty high degree of scrutiny. To the extent you have a third party in there with an arm's-length negotiated transaction related to the same property, it really helps that situation.

I don't think we have to have a partner. We would love to have one. I think it does a couple of things. It addresses the arm's-length issue, but it also allows us to increase the size of the program. When you get some economies to scale from drilling costs and service costs and other things like that by having a larger program larger drilling program than you would otherwise have if you went it alone.

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

Really both. Both unfold in pretty quick timeline here in the next few weeks. The commissioner recusal issue comes first and then the actual RRR request for rehearing reconsideration, that's next. And it's got a fairly short time fuse. By the end of February we'll be through that process. We'll see what we end up with for a result there.

If we're not comfortable with that result that's consistent with state law, namely the Colorado Clean Air Clean Jobs Act, we would likely appeal to the court system after that. We're hopeful that going through the commission process, particularly with a couple new commissioners here, that we'll reach a reasonable outcome that's consistent with state law and prior commission precedent.

Thank you. That's all I have.

Andy Levi, Avon Capital Advisors

Good morning, guys. Just on -- because we didn't talk about it in detail, and I don't know if you guys are prepared to yet, but on tax reform, is there any type of high-level beyond obviously we don't know what the rules are, but whether it's interest deductibility, a lower tax rate, how that may affect some of the numbers particularly at the parent?

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

How much parent debt do you guys have once the converts -- kind of back that out? If that converts next year?

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

Okay, so once you get through that convert, you're saying there's only $500 million of debt that's at the parent level that's not allocated to the utilities?

Well, the parent debt is going to be about $2.9 billion.

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

I can't answer that off the top of my head, Andy. I'd have to go look. I think our all-in weighted average rate of interest right now is about a little over 4%. 4.25%-ish.

Right. Do you benefit from any type of [repair] tax deductions or anything like that?

Yes, we do.

Can you quantify that?

No. Not off the top of my head.

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

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

So for 2017 what do you guys have embedded in the guidance as far as the tax rate?

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

Okay, more normalized rate. That's good. Just back on the $2.9 billion. Does that include the convert or not?

That would be after the convert converts.

Great. Thank you very much.

All right. Thank you, Andy.

(Operator Instructions)

Jim Marrone, Singular Research

Good morning, gentlemen, and congratulations on a good quarter.

Thank you.

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

Of course. We're always looking. The issue right now is just given our balance sheet, it would be hard for us to lever up enough to be competitive on a large-scale acquisition that had a lot of interest from other parties. But if we were to find a little tuck-in acquisition someplace where it really made great sense for us, we wouldn't have any problem doing that.

Rich mentioned we've got the ATM program. We've got some other things we could use to finance that. But big acquisitions, even though we might be interested in look right now, I think we'd be fooling ourselves if we thought we could be as competitive as we were with SourceGas just because we just don't have a leverage capacity that we did with that one. And we won't until 2018 and after the converts and all of that.

While we're always looking for the right opportunity, certainly our competitiveness is going to be effected for any large ones in the next couple of years.

Okay. Great. Thank you, gentlemen.

Thank you.

Lasan Johong, Auvila Research

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

The Piceance has the capacity to provide a very large program, Lasan, with, frankly, resources to spare. So there is not an issue there.

I think if we get a program up and running, the only question for the long term is do we want the entire program based on a single asset just from a diversity of market, diversity of cost, and other perspectives. But that's a problem that would occur multiple years down the road if we are successful in getting a program in place. But based on what we see for our needs and the potential parties that we've been talking to, the Piceance could easily supply those programs. It's just whether you would want them to for the long term.

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

I think the issue there, Lasan, is how much capital do you have to put in to prove the viability of the play. And in the Mancos, it's our view that we've put sufficient capital in there and done enough well testing and drilling that we have a pretty good handle on forward economics. And so I think without cost of service gas it doesn't make sense for us to continue spending because we don't need it to really value the property.

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

Beggars can be choosers, if you will. We like growing our utility businesses, and you can't predict when something's going to become available or what's going to become available. We've said in the past that if you had a wish list, it would be an electric utility that needed power generation. Those two things are sweet spots for us.

When you look at Cheyenne Light, you look at Colorado Electric, both were opportunities to buy electric utilities that were in desperate need of generation resources at a size that our folks are great at building and operating. So in an ideal world, that would be the top of your wish list. It's just you can't make those transaction happen that way.

And right now we've got a great mix. We're about 50/50 gas and electric on assets, EBITDA, et cetera. So we kind of like having that risk profile that way.

Okay. Last question. The PUC made a decision to reward $1.2 million for the renewal project. That's a 52.5-year payout. How do they justify that without basically saying we don't care about shareholders?

A couple issues there, Lasan, and again not to dodge your question, but I think the best source of all the specifics -- and maybe you've read it already -- is our request for the RRR has very good detail in what's happening there. But as I said in my prepared comments, we had a pre-approved construction financing rider as part of the Clean Air Clean Jobs Act.

At the end of the year, the rate that we were collecting that was about $5.9 million a year. That will be annual, recurring revenue. And we got a $1.2 million on top of that. It's still not a good decision. We're very disappointed in it, but it's not $1.2 million in revenue on a $63 million asset.

Okay. That's what I thought. All right. Thank you very much for your time.

Thank you.

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

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

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