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IDACORP’s (IDA) CEO Darrel Anderson on Q4 2015 Results – Earnings Call Transcript

Operator Welcome to IDACORP’s Fourth Quarter 2015 Conference Call. Today’s call is being recorded and webcast live. A complete replay will be available from the end of the day for a period of 12 months on the company’s website at www.idacorpinc.com. [Operator Instructions] At this time, I would like to turn the call over to Mr. Lawrence Spencer, Director of Investor Relations. Please go ahead, sir. Lawrence Spencer Thanks, Karen. We issued our earnings release and Form 10-K before the markets opened today and they’re both posted to the IDACORP website. The slides we will be using to supplement today’s call can be found on our website as well. We’ll refer to these slides as we work our way through today’s presentation. On today’s call we have Darrel Anderson, IDACORP’s President and Chief Executive Officer and Steve Keen, Senior Vice President, Chief Financial Officer and Treasurer along with other individuals to help answer your questions during the Q&A period. As noted on Slide 3, our presentation today will include forward-looking statements. While these forward-looking statements represent our current judgment or opinion of what the future holds, these statements are subject to risks and uncertainties that may cause actual results to differ materially from forward-looking statements made today. So we caution you against placing undue reliance on forward-looking statements. Some of the factors and events that could cause future results to differ materially from those included in forward-looking statements are listed on Slide 3 and are included in our filings with the Securities and Exchange Commission, which we encourage, you to review. On Slide 4, we present our quarterly and year-to-date financial results. IDACORP’s fourth quarter 2015 earnings per diluted share were $0.63, a decrease of $0.06 per share from last year’s fourth quarter. For 2015 earnings per diluted share were $3.87, $0.02 greater than 2014. I’ll turn the presentation over to Steve to discuss the results in greater detail and to review our 2016 key operating metrics. Steve Keen On Slide 5, we present a reconciliation of earnings from 2014 to 2015. Overall net income increased by $1.2 million over the period. The combined positive effect of customer growth effects cost adjustment mechanism and other revenue in 2015 increased operating income by $26 million compared to 2014. Lower usage per customer and higher operating and maintenance expense combined with higher depreciation expense and property taxes to partially offset the increase in operating income by $17.1 million. When combining the above changes with $21.5 million increase in earnings resulting from reduced Idaho sharing, Idaho Power’s operating income was $30.4 million in 2015 than in 2014. An additional $7.2 million increased to earnings in 2015 reflects a flow through benefit from a tax deductible make-whole premium from an early redemption of long-term debt. These amounts are reduced by higher income tax expense of $11.1 million primarily due to greater Idaho Power pre-tax earnings and the $24.5 million tax benefit from the 2014 method change that did not recur in 2015. Moving now to Slide 6, we show IDACORP’s operating cash flows for 2015 and 2014 along with the liquidity position for December, 31. Cash flow from operations for 2015 was approximately $353.2 million, a decrease of $11.1 million from 2014 primarily resulting from timing and decrease in working capital. IDACORP and Idaho Power currently have in place credit facilities of $100 million and $300 million respectively, to meet short-term liquidity and operating requirements. The liquidity available under the credit facilities is shown on the bottom of Slide 6. Also there are $3 million IDACORP common shares available for issuance under IDACORP’s continuous equity program. No shares were issued, during 2015 and we do not expect to issue new equity, during the remainder of 2016. Turning to Slide 7, we’re estimating 2016 O&M at between $350 million and $360 million. This is slightly higher than last year’s opening guidance by just under 3%. Actual 2015 expense of $342 million came in at the low end of our prior guidance range. Primarily, due to lower than expected thermal operating cost at our coal facilities. In 2015, we recorded approximately $3 million of current revenues to be refunded to Idaho’s customers and did not amortize any additional accumulated deferred investment tax credit or ADITC, under our current Idaho regulatory settlement stipulation. For 2016, we forecast using less than $5 million of additional ADITCs to attain a 9.5% return on yearend equity in our Idaho jurisdiction. In projecting this range, we evaluated a number of scenarios including the potential benefits that could result from refinancing, a series of bonds during 2016. We did a similar but larger bond refinancing in 2015 and ahead of favorable impact on impact tax expense. Impending on interest rates and timing, decision to refinance bonds again this year could have an approximate $4 million net tax benefit to earnings. Our estimated capital expenditure range for 2016 is between $300 million and $310 million, which includes between $20 million and $25 million for emission control equipment at the Jim Bridger plant. In the liquidity and capital requirement section of the 10-K we filed today. We have included some examples of other ongoing infrastructure projects. For 2017, the estimated capital expenditure range moves to between $275 million and $285 million. In total over the next five years estimated capital expenditures are between $1.4 billion and $1.5 billion. On the next row of Slide 7, we show that our expected 2016 hydroelectric generation ranges from 6.0 million megawatt to 8.0 million megawatt hours. This figure is lower than our opening guidance in 2015, but reflects improved expectations over our 2015 actual result. As a reminder, the Median annual hydroelectric generation is 8.5 million megawatt hours. Finally, we are initiating our 2016 earnings per share guidance in the range of $3.80 to $3.95 per diluted share, which reflects normal weather conditions and our expectations for continuing cost management. I’ll now turn the presentation over to Darrel. Darrel Anderson Thanks, Steve and welcome to all of you joining us on the call this afternoon. And at first, I just would like to thank all of you on the phone for your support throughout the year, we appreciate that very much. I will update you on a few items related to our business and then we’ll look forward to your questions. Turning to Slide 8. As we began 2016, we reached an existing company milestone. Idaho Power’s centennial. For 100 years, we have provided reliable, responsible, fair pricing energy services to our customers, while continuing to provide a solid investment option to our owners. As we look back at the strong foundation that lead to the success and longevity of the company. We also look forward to the challenges and opportunities that the next century provides, as we continue on as an independent integrated electric utility. Our focus remains on our core business. 2015 marks IDACORP’s eighth consecutive year earnings per share growth, which has been positive for both our shareholders and our customers. As Steve noted in 2015, Idaho Power recorded no additional ADITC amortization leaving $45 million of additional ADITC available for future use. Our earnings for the year resulted in sharing approximately $3 million with customers. This continued the trend of several years of sharing with customers amounting to more than $120 million. There have been major changes in our industry over the last 100 years. But much has remained consistent. We keep our owners, customers and employees top of mind, along with an emphasis on revenue growth and optimization in all areas of the company. In addition, we focus on a purposeful succession plan for our leadership positions. Last week, we announced that our Vice President of Regulatory Affairs, Greg Said will be retiring after over 35 years with the company. Because of our purposeful efforts around building our bench, we will see a seamless transition in this key role with the appointment of Tim Tatum to succeed Greg effective March 1. Tim has been integral to our regulatory efforts over the years and will bring with him, 20 years of experience from customer service to regulatory activities, with our company. We thank Greg for his many years of service and wish him the best in the next chapter of his life. Moving to Slide 9, Idaho Power service area experienced strong customer growth in 2015 registering 1.8% increase from 2014 to 2015. Idaho Department of Labor data shows that the number of people employed in Idaho Power service area increased by over 22,000 from December, 2014 to December 2015, an increase of 4.9%. Also in December 2015, the unemployment rate in Idaho Power service area was a low of 3.9% which compares favorably to the US rate of 5%. Another indicator of growth in our state, is United Van Lines Annual Movers Study that was released at the beginning of this year. Idaho Power, Idaho has moved up from the 10th position in 2014 to the 4th spot in 2014. The survey tracks customer state-to-state mitigation patterns over the past year and further supports our belief in the attractiveness of the state of Idaho and our service area. As we move into 2016, a few key items that you should watch for include the following; based on what we know today, we do not expect to file a general rate case in 2016. But we will continue to evaluate the timing of a general rate case. We do expect our PTA and STA to be filed on their normally scheduled timeframes. We expect the Bureau of Land Management to issue a final environmental impact statement during 2016 and a record of decision in late 2016 or early 2017 on the Boardman to Hemingway Transmission mine project. While this does not complete the required permitting process, these are key milestones for the project. We continue to expect this project to become in service in 2022 or beyond. We also anticipate making a final decision on our participation in the Western Energy and imbalance market during 2016. We expect that participation in the imbalance market will provide benefits that should reduce net power supply cost and customers that modest benefits back to owners. Switching gears, we are proud to announce that a few days ago, we launched a new IDACORP website. You can see part of this new homepage on Slide 10. Today, the site is available for you and anybody else looking for information about the company. I think you’ll find it cleaner, clearer and easier to use. When you have a moment, please visit idacorpinc.com and check it out. And if you have suggestions for improvement or information that you would like us to consider adding, please let us know. I’d like to thank Larry Spencer and Justin Forsberg for help spearheading this effort along with our corporate communications, information technology team and making this happen to help enhance the investor experience. Finally, let us move to Slide 11, for a look at what Mother Nature may have in store in the spring, precipitation and temperature forecast. According to the National Oceanic Atmospheric Administration in March through May, we are looking at about 33% to 40% chance of above normal precipitation in the southern portion of our service area and normal precipitation level in the northern portion. The spring outlook also shows a 33% to 50% chance of above normal temperatures. Idaho Power stands ready to meet the expected energy needs of our customers, no matter how the weather develops. Also remember, that in annual power cost and fixed cost adjustment mechanisms allow us to share most of both of those risk and rewards of water and weather-related conditions with our customers. Now Steve and I and other on the call today, will be happy to answer, any questions you have. Question-and-Answer Session Operator [Operator Instructions] Paul Ridzon from Keybanc. Paul Ridzon I had a question, to Steve. Does the FCA capture variations in usage patterns or is that just designed to capture weather variances? Underlying the usage per customer kind of conservation. Steve Keen Yes, the FCA is really designed to be a somewhat of a proxy for the use of customers, and so as use declines. It does recover some of that cost. The term that slipped in my mind right this moment that it’s, it’s a decoupling mechanism that we put in place and it helps us, I get the account for that because you made an assumption during the rate case, that isn’t exactly playing out, as you had declining usage per customer. So that’s. Paul Ridzon Weather or conversation gets captured. Steve Keen Well it does now, previously there had less of a weather components that with the change that they put in the spring last year, is now really adjust to actual so it’s picking up more than just component to use. Paul Ridzon And can you give us sense of, what do you expect the effective tax rate to be as somewhat little bit higher this year given that last year, you had the deduction for the debt premium? Steve Keen The guidance that Gene [ph] and I talked about was, it’s still in low 20s. And I think that’s, it is a little more variable but, I think that’s still a reasonable number to assume, going into it. And I wanted to just follow up, Paul on your first question. That FCA is focused to residential and small commercial customers only. Paul Ridzon And then lastly I saw in your Form 10-K, you painted it looks like a $30 million premium for corporate life insurances, is that a new program or can you just give us some background there? Steve Keen Well, that’s simply an investment vehicle. It is, a Rabbi trust that is there, that we’ve funded over the years and those funds were just in different investments that’s simply a life insurance product that is means of investing. That’s all it was and the funds really were there previously. So it was really a transfer from one investment to another. Paul Ridzon Thank you, very much, everyone. Operator [Operator Instructions] I do have a question from the line of Brian Russo from Ladenburg Thalmann. Brian Russo Could you maybe talk about the timing that you are considering some refinancing this year? Steve Keen I guess, we haven’t set our timing at this point. But we basically, get through year end and then we start watching the market and looking based on needs. One thing we have to expect now is, just how much do we need, which we’re watching that. We had a little more defined need, I think coming into last year. But we always approach that somewhat from opportunistic standpoint. Brian Russo And is the refinancing captured in the guidance? Steve Keen You’re talking about, if we were to do – you’re talking about calling early bonds. Brian Russo Yes, exactly, that is a positive tax bracket [ph]. Steve Keen Those are, it’s really kind of two separate things. You can call bonds and you can financing, they don’t have to be connected. But, what we have that in my script. I mentioned that we included that in the scenarios we looked at and even with that. There is possibility, that you could use some credit. There are things that move up and things that move down and it depends on what combination it shows up, where we ultimately in. We opted to say zero to $5 million as the place we felt, most comfortable coming out with guidance. Brian Russo Right. Okay. And what’s driving the O&M higher? Because you’ve been pretty disciplined over the last couple of years with kind of flattish O&M, just curious what’s driving it higher in 2016. Steve Keen Again, if you look at that’s why I put a little bit of comment in there. Partly, we had really good success this past year and some of the O&M we had planned on went down. So we look a little less successful against that low number. Year-over-year if you look at, taken the midpoints of the ranges and compare them, it’s sub-3% and I would argue that you can’t hold flat forever, we do have pressures and wages and government entities and other things, that raise our cost, that we don’t really have a choice but to deal with. That doesn’t mean we won’t attempt to make further savings and to do better, as we go forward. As you saw, last year we actually came in at the low end of the range. So we’ll do everything we can, as we move through the year to manage that O&M cost. Darrel Anderson Brain, it’s Darrel. One thing, I just add on the O&M side is, we have had again we run our gas lines pretty hard until we do have a periodic maintenance expense coming in at Langley Gulch that will be happening in 2016, that wasn’t necessarily there in 2015, doesn’t happen every year. It all depends on the amount of usage and since we ran that pretty hard in 2015, we got there may be more closer than we thought. So we do have a periodic enhancement and the expenses there. That relates the Langley results. Brian Russo Okay. Then lastly, when do you expect the Jim Bridger upgrade to be completed? Darrel Anderson So this is Darrel, I’ll start and Steve maybe finishes. That we did finish, unit three in 2015 and unit four is scheduled in this year. Brian Russo Right. I’m curious as to the timing in 2016. Steve Keen That’s mid-year. Darrel Anderson I think it’s in and around mid-year, end of second or early third quarter. Brian Russo Great, thank you. Operator Thank you and that concludes the question-and-answer session for today. Mr. Anderson. I’ll turn the conference back to you. Darrel Anderson Again, for all of you on the call. Thank you very much for your interest in IDACORP and Idaho Power. We wish you the best for the rest of your day. Thanks a lot. Operator And that concludes today’s conference. Thank you for your participation. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. 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Empire District Electric’s (EDE) CEO Brad Beecher on Q4 2015 Results – Earnings Call Transcript

Operator Welcome to the Empire District Electric Company Year-End Fourth Quarter and 2015 Results Conference Call. [Operator Instructions]. I would now like to turn the conference over to Dale Harrington, Secretary and Director of Investor Relations. Please go ahead, sir. Dale Harrington Thank you, Dan and good afternoon, everyone. Welcome to the Empire District Electric Company’s year-end 2015 earnings conference call. Our Press Release announcing fourth quarter and year-end 2015 results was issued yesterday afternoon. The Press Release and a live webcast of this call, including our accompanying slide presentation, are available on our website at www.empiredistrict.com. And a replay of the call will be available on our website through May 5, 2016. Joining me today are Brad Beecher, our President and Chief Executive Officer and Laurie Delano, our Vice President, Finance and Chief Financial Officer. In a few moments, Brad and Laurie will be providing an overview of the fourth quarter and year-end 2015 results and 2016 expectations as well as highlights on some other key matters. But before we begin, let me remind you that our discussion today includes forward-looking statements and the use of non-GAAP financial measures. Slide 2 of our accompanying slide deck and the disclosure in our SEC filings present a list of some of the risks and other factors that could cause further results to differ materially from our expectations. I’ll caution these lists are not exhaustive and the statements made in our discussion today are subject to risks and uncertainties that are difficult to predict. Our SEC filings are available upon request or may be obtained from our web site or from the SEC. I would also direct you to our earnings Press Release for further information on why we believe the presentation of estimated earnings per share impact of individual items and the presentation of gross margin, each of which are non-GAAP presentations, is beneficial for investors in understanding our financial results. With that I’ll now turn the call over to our CEO, Brad Beecher. Brad Beecher Thank you, Dale. Good afternoon, everyone. Thank you for joining us. Today we will discuss our financial results for the fourth quarter and 12 months ended December 31, 2015, period as well as recent activities impacting the Company. As communicated in yesterday’s earnings release, with regard to the strategic alternatives process confirmed in our December 13, 2015, news release we have no update. Moving on to our year-end results, we expected 2015 earnings to be impacted by a regulatory lag associated with the Asbury Air Quality Control System project and they were. Unfortunately, mild weather, particularly in the fourth quarter, also negatively affected earnings. In terms of heating-degree days, December and the fourth quarter 2015 were the mildest in over 30 years. Despite the mild weather, we achieved success in many areas. Our retained earnings reached $100 million for the first time. We have a healthy balance sheet and a sustainable dividend. We continued to improve service reliability for our customers and it was another good year for our employee safety performance. As shown on slide 3, yesterday we reported consolidated earnings for the fourth quarter of 2015 of $9.9 million or $0.23 per share compared to the same quarter in 2014 when earnings were $11.1 million or $0.26 per share. Earnings for the year ended December 31, 2015, were $56.6 million or $1.30 per share, $1.29 on a diluted basis, compared to 12 months ended 2014 earnings of $67.1 million or $1.55 per share. During their meeting yesterday, the Board of Directors declared a quarterly dividend of $0.26 per share, payable March 15, 2016, for shareholders of record as of March 1. This represents a 3.5% annual yield at yesterday’s closing price of $29.45. I’m pleased to report our largest single construction project for the year, the Riverton 12 combined cycle unit, is progressing on schedule. During the fourth quarter, we completed construction work in the equipment integration outage. This past weekend, the project team successfully ran the steam turbine at full operational speed for the first time. I’m happy to report as of this morning, the unit was synchronized to the grid or in other words produced electricity for the first time. Additional operational performance and in-service tests will occur over the next several weeks. We remain on target to complete the project late in the first quarter or early in the second quarter of 2016. Our current projections indicate the combined cycle unit will come in at the lower end of the $165 million to $175 million budget range; however, this is dependent upon the amount of test fuel burned, test energy sales margin and any other unforeseen issues. As we reach the final stages of the Riverton project, the completion of our multi-year compliance plan to reduce fossil fuel emissions is nearing conclusion. We have adequate production capacity and continue to be fully compliant with all current environmental standards. We remain engaged at the local state and federal levels relating to the development of implementation plans for the Environmental Protection Agency’s clean power plan. We believe this regulation will drive significant change in the way electricity is generated in the future, even though there is still uncertainty surrounding the details of implementation plans. You will recall we filed a Missouri rate case last October, primarily to recover costs associated with the Riverton investment. The filing seeks an increase in base rate revenues of approximately $33.4 million or about a 7.3% increase. The procedural schedule provides for a trueup of expenditures incurred through March 31, 2016. This includes rate base items associated with the Riverton project provided it meets in-service criteria by June 1, 2016. The Missouri Commission has scheduled local public hearings for the case in April and evidentiary hearings in Jefferson City beginning May 31. We expect new rates to become effective late in the third quarter. We have also made a corresponding filing in Oklahoma. An administrative rate reciprocity rule now in effect provides for our approved Missouri rates to be applied in our Oklahoma jurisdiction, of course, subject to approval by the Oklahoma Commission. As a reminder, we’re currently recovering our Asbury Air Quality Control system investment through riders in both Kansas and Arkansas. We have a separate rider in place in Kansas to recover increased property taxes. In January, we filed a request to increase the rider by $0.2 million to reflect increased property taxes for the Riverton project. We expect to file a full-year full rate case in Kansas by the end of the third quarter and in Arkansas no later than the end of the year. For 2016, we expect earnings to be within a weather-normalized range of $1.38 to $1.54 per share. This reflects a full year of recovery for expenses related to the Asbury Air Quality Control system and the expectation of a partial year of new rates for the Riverton project. I will now turn the call over to Laurie to provide additional details of our financial and our 2016 earnings guidance. Laurie Delano Thank you, Brad. Good afternoon, everyone. As always, the information I’m about to discuss today will supplement the Press Release we issued late yesterday and as always the earnings-per-share numbers referenced throughout the call are provided on an after-tax estimated basis. I I’ll briefly touch on our 2015 fourth quarter results before I discuss our annual results. Our fourth quarter earnings of $0.23 per share is reflective of much milder winter weather when compared to the previous year’s fourth quarter. In particular, mild December 2015 weather resulted in the lowest number of heating-degree days in 30 years, so the mild quarter weather was the primary driver of a 6.3% decrease in quarter-over-quarter electric sales. Slide 5 shows the quarter-over-quarter changes that impacted earnings per share. Electric segment gross margin or revenues less fuel and purchase power expense, increased $2.3 million, increasing earnings by $0.02 per share. Increased customer rates of about $6.2 million, net of an estimated $1.8 million decrease in Missouri-based fuel recovery, increased revenue $4.4 million quarter-over-quarter. This added an estimated $0.09 per share to margin. This increase was almost entirely offset by the impact of the mild weather and other volumetric factors which decreased revenue by about $8 million, negatively impacting margin by about $0.08 per share when compared to last year. Positive customer growth contributed about $0.01 to earnings per share. Other items including Southwest Power Pool integrated market activity and the timing of our fuel deferrals along with our non-regulated revenues combined to add another estimated $0.02 per share to margin when compared to the fourth quarter of 2014. Mild weather also impacted our gas segment retail sales quarter-over-quarter, driving a decline of just over 27% in total sales volume. This resulted in a decrease in gas segment margin of about $0.02 per share. Consolidated operating and maintenance expenses were relatively flat compared to the 2014 quarter, but added another $0.01 to earnings per share. Higher depreciation and amortization expense reflective of higher levels of plant and service, primarily due to our Asbury project reduced earnings per share around $0.03. Changes in interest costs, AFUDC and other income and deductions reduced earnings per share another $0.03 compared to the prior-year quarter. Turning to our annual results, our net income decreased approximately $10.5 million or around $0.25 per share compared to the 2014 full-year results. Slide 6 provides a breakdown of the various components that resulted in this year-over-year earnings-per-share decrease. Consolidated gross margin increased $6 million over 2014, adding an estimated $0.09 per share. As shown in the callout box on slide 6, we estimate that increased customer rates from our July 2015 Missouri rate case added about $0.15 per share to margin. This is reflective of increased customer rates of about $10.4 million netted with a $3.3 million lowering of our base fuel recovery, ultimately adding an estimated $7.1 million to revenue. We estimate the impacts of weather and other volumetric factors on the electric side of the business reduced revenues an estimated $10.3 million year-over-year. This negatively impacted margin by about $0.10 per share, partially offsetting the increase in earnings driven by the customer rate changes. Increased customer growth added about $0.02 per share to margin and, as in the quarter, Southwest Power Pool integrated market activity and timing differences of our fuel deferrals and other fuel recovery components drove a $0.07 per share margin increase when compared to the 2014 period. A January 2015 FERC refund to four of our wholesale customers reduced margin about $0.02 per share and other miscellaneous and non-regulated revenues combined to increase margin about $0.01 per share. Again, the mild weather impacted our gas segment, driving a margin decrease of about $2.6 million for the year or about $0.04 per share. Increases in our consolidated operating and maintenance expenses decreased earnings about $0.07 per share. The callout box on slide 6 provides a breakdown of this impact. Increased production maintenance expense was the significant driver of the increase in overall O & M expenses. As I mentioned on our previous call, this increase is reflective of our Riverton 12 maintenance contract which was effective January 1, 2015. In addition, it reflects the planned major maintenance outage for our steam turbine at our State Line combined cycle facility. These added expenses reduced earnings about $0.05 per share. Higher production operations expenses, primarily from the increased use of consumables, reduced earnings another $0.03 per share. And as you can see on the slide, increased transmission operations and employee healthcare expenses were offset by decreases in customer and distribution maintenance expenses. Continuing on slide 6, depreciation and amortization expenses decreased earnings per share about $0.11, driven by higher levels of plant and service, again, primarily as a result of our Asbury project. These higher levels of plant and service also drove an increase in property taxes bringing earnings down another $0.04 per share. Increased interest expense reduced earnings per share about $0.05 year-over-year. This reflects our two $60 million debt issuances completed in December 2014 and in August 2015. Reduced AFUDC levels, changes in other income and deductions and the dilutive effect of common stock issuances under our various stock plans combined to round out the remaining $0.07 decrease in earnings per share. As illustrated on slide 7, our actual 2015 results of $1.30 basic earnings per share were, of course, at the bottom end of our guidance range, due primarily to the mild weather during the fourth quarter of 2015. We estimate the impact of the mild fourth quarter weather reduced earnings about $0.07 to $0.09 per share compared to normal. Absent this weather impact, we would have been very close to the midpoint of our 2015 guidance range. As Brad mentioned earlier, we expect our full-year 2016 weather normalized earnings to be within the range of $1.38 to $1.54 per share. On slide 8, we highlight the drivers of our increase in earnings expectations in 2016. As in the past, our estimates are based on normal weather and modest positive sales growth which, as we have previously disclosed, we still expect to be at a level of less than 1% per year over the next several years. We’re also assuming our Missouri rate case filed last October to recover Riverton 12 combined cycle costs will be effective as filed with rates effective in mid-September of this year. Depreciation expense will increase, reflecting our previously disclosed expectation of the Riverton 12 project in-service date in the early to mid-2016 time period at an estimated 30-year live rate. In addition, depreciation will increase for assets placed in service since our last rate case. The impact on depreciation of the Riverton 12 project alone is estimated at approximately $0.05 to $0.06 per share on an annualized earnings-per-share basis. We will also see increases in property tax and interest expense. The higher interest expense, of course, reflects our previously discussed August 2015 debt issuance. It also reflects the redemption of $25 million of our first mortgage bonds which are due in late 2016 and as indicated previously we’re not planning on refinancing this debt when it matures. And last but not least, our AFUDC impact will be lower in 2016 as the Riverton project comes online. Other factors we considered in our range are variations in customer growth and usage as well as variations in operating and maintenance expense. On slide 9, we have updated our trailing 12-month return on equity chart and as you can see at the end of 2015, our return on equity was approximately 7.1%. I’ll also mention that we have not made any changes to the capital expenditure plan we discussed on our last call. Turning to our recent regulatory activity, slide 10 once again summarizes the key aspects of our Missouri rate case filed October 16, 2015. As filed, we’re seeking a $33.4 million increase in base revenues which is about a 7.3% increase. Our requested return on equity is 9.9% and we’re using a capital structure of approximately 51% debt and 49% equity. The filed Missouri rate base is approximately $1.4 billion. The procedural schedule has been set by the commission. The test year ends June 30, 2015, with trueup expenses through March 31, 2016. Rate based items for Riverton 12 through March 31, 2016, may be included if the in-service criteria for the Riverton 12 project has been met by June 1. As Brad noted, we’re making good progress on meeting the in-service criteria. Slide 12 gives you a projected timeline for the case proceedings. Our solar program compliance costs are also included in this Missouri rate filing and Brad will provide an update on this program in his wrapup of our presentation. Similar to our previous rate case to recover our Asbury environmental expenditures and as you can see on the projected timeline, we will experience a period of lag between the in-service date of the Riverton 12 conversion and the time when new customer rates are put in place. Assuming the Missouri Public Service Commission’s 11-month procedural schedule, new rates will become effective in mid-September 2016. I’ll now turn the discussion back over to Brad. Brad Beecher Thank you, Laurie. This past year we implemented a mandated solar rebate program resulting in 767 customer applications as of December 31. The applications represent a total of 11.5 megawatts of customer- owned solar installation which aid in meeting the solar requirements of the Missouri renewable energy standard. Through the end of the year, we have booked $3.5 million in rebates. And as Laurie mentioned, the recovery of the rebates paid through the end of the year is included in our pending Missouri rate case. Any additional costs or rebates incurred through the trueup period will be reflected in the results of our rate case. We’re also very pleased to report that our customers experienced improved service in 2015 as we continued focus on system reliability. We reduced the average number of outage occurrences and the duration of outages affecting customers by 7% and 13% respectively. Continuous improvement in the efficiency of our operations is the goal of another major project undertaken this past year. After months of preparation, a project team is preparing to launch what we term the power delivery construction bundle of our new work management software platform. The new system will aid in the standardization of the design and construction of transmission, distribution and substation equipment. We expect to realize significant cost savings from these efficiency improvements. It is also been a good year on the economic development front. As we have reported earlier, Owens Corning is establishing a new manufacturing operation just west of Joplin. They’re investing $90 million in a mineral wool installation production facility that will employ over 100 workers. We have a substation upgrade underway to accommodate a June startup for the facility and we’re developing plans to construct a new substation to serve the five to six megawatts of load expected when this facility is fully operational. Excitement continues to remain high for the new medical school being established in Joplin which we reported on earlier this year. The new medical school is being developed by Kansas City University of Medicine and Biosciences and will have over 600 students when it reaches full enrollment in 2020. The project is expected to have an annual economic impact for our region of over $100 million. On the legislative front, Senate Bill 1028 was filed in the Missouri Senate this week which states an intent to modernize the regulatory process for electrical corporations in Missouri. It proposes four general provisions. First, consumer protection such as earnings caps, rate caps and performance standards. Second, more timely recovery of the utilities prudently incurred operating costs. Third, policies that encourage investment in Missouri electrical infrastructure. And finally, globally competitive rates for energy- intensive customers. Details are not included in the bill, but we anticipate that additional language will be added as it moves through the legislative process. I will now turn the call back over to the Operator for your questions. Question-and-Answer Session Operator [Operator Instructions]. Our first question comes from Brian Russo of Ladenburg Thalmann. Brian Russo Just to follow up on the Senate Bill 1028. Maybe you could add your view as to what’s different with this bill proposed versus prior bills that didn’t make it out of committee. Brad Beecher I would tell you this time there is a lot more work on consensus on the front end of the process. And, as you can see, if you’ve looked at Senate Bill 1028, it’s one page and really doesn’t have any details. And that’s because all parties are still working very hard on trying to reach consensus before we try to push this forward in a utility committee. Brian Russo And who are the parties? I would imagine there are some large industrial customers? Brad Beecher It’s the same general set of parties that are always participatory in Missouri proceedings. This time it’s a little bit different because Noranda [ph] is helping try to find a good solution for them as well. But it’s – really the Missouri Industrial Energy consumers group is probably the biggest opponents as we sit here today. Brian Russo Okay, got it. And this is just the electric utilities, right, not all utilities? Brad Beecher Senate Bill 1028 is just an electric bill. There are two other bills, there’s a – and I don’t know the numbers off the top of my head, but there’s a gas esters and there’s also a water decoupling bill that are making their own pathways through the Missouri legislature. But all three bills, to my knowledge, are being supported by all the MEDA entities within Missouri – and, MEDA being the Missouri Energy Development Association. Brian Russo And when does the legislature end? Brad Beecher Sometime around the first of May. That’s not exactly right, but sometime in May. Brian Russo And then, you mentioned your CapEx is the same. Does that imply that your prior rate-base slide is also the same? Laurie Delano Yes, it would, Brian. Brian Russo Okay, so there’s no impact from bonus depreciation? Laurie Delano Yes, in the near term we don’t think there’s much impact from bonus depreciation. What it impacts more is the outer years. And so we will have that updated in our analyst presentation when we file it. Brian Russo And then, the $33.4 million revenue request in the Missouri rate case, how much of that is Riverton? Laurie Delano We estimate that the total effect of Riverton is about $27.4 million of that. And that includes return on and of and expenses associated with Riverton. Brian Russo And will there be a net offset from lower fuel? Laurie Delano We’re not expecting one in base rates, no. Brian Russo And then, just referring to the prior rate-base disclosures. Rate base seems to be leveling off in 2018 versus 2017. I’m just curious, how do you achieve earnings growth as rate base levels off? Is it just less regulatory lag or an ROE improvement or is there incremental CapEx that’s being considered? Brad Beecher That’s the question of the day – how do you grow if you don’t have a lot of plant growth? And so we continue to analyze alternatives to grow rate base in those outer years. Brian Russo Okay. And then, just elaborate on what gets you to the high end of the 2016 guidance range. Is it just a constructive outcome in the rate case or what would drive that? Weather? Laurie Delano A couple of things would drive that. Managing our O&M expenses to under budget is one of our considerations. If the growth in our area would be a bit higher than what we have laid into our budget, those are really the two things that we have that would have the most impact. Brad Beecher Brian, you asked if it was weather. And we give weather-normalized guidance and so our entire guidance range covers just normal weather. Operator The next question comes from Paul Ridzon of KeyBanc. Paul Ridzon Brad, you mentioned you filed in Oklahoma. How do you envision that process unfolding to sync the rates up? Brad Beecher Last year, Oklahoma initiated a process whereby if you had a very small number of customers in Oklahoma and you were next to a state with a larger jurisdiction, you could simply file – in this case – Missouri’s rates in Oklahoma. So we’re the first company to go through that. And so Oklahoma is watching what’s going on in our Missouri case, but we would anticipate, at the conclusion of the Missouri case, working with the Oklahoma staff and Oklahoma Commission to implement those same rates in Oklahoma. But it’s the first time, so we’re not exactly sure how that’s going to work. But, so far, discussions with Oklahoma staff have been going very well. Paul Ridzon And when did you expect those new rates to take effect? Brad Beecher Shortly after the Missouri rates take effect. Paul Ridzon We’re just not sure what the process looks like, so whether they get phased in or whether they can come all in at once? Brad Beecher We have to work with the Oklahoma staff to determine how that works. Paul Ridzon Okay. And then, you said today you thought Riverton was going to come in at the low end of the budget? Brad Beecher That’s correct. Paul Ridzon And there’s a nice pick-up in industrial load in the fourth quarter. What was driving that? Laurie Delano Well, we have, if you’ll recall, in the past discussions, we’ve talked about our new dog-food plants that came to Joplin as a result of the tornado. And then, we’ve just seen some other general increases in some of our other customers, but that would be the main driver of that. Paul Ridzon Then, can you quantify what you expect the lag impact to be on earnings-per-share basis with Riverton? Laurie Delano Well, we’ve said that the depreciation alone would be about a $0.05 to $0.06 earnings per share per year on an annualized basis. Obviously, for 2016, you’re not going to have that much impact for that piece of it. Property taxes, we didn’t really quantify specifically what that was. The depreciation is the biggest direct expense lag that we would have. Paul Ridzon The depreciation is the return of capital and then we’re also lagging on return on capital and then operating expenses? Laurie Delano You’d also have the return on capital. Those would be the two major items. Paul Ridzon And, Brad, I appreciate you’re limited in what you can say. Can we expect that the next commentary you make around strategic review will be an up or down? Give us a final answer, there is a transaction or there is no transaction? Brad Beecher I appreciate the fact that you have to ask, but I have no update on that topic today. Operator Our next question comes from Glenn Pruitt of Wells Fargo. Glenn Pruitt I have two questions. One relating to January weather. Can you give me some indication of January weather, where it is, relative to normal and if there’s any impact to 2016 relative to your guidance range? Brad Beecher You live just on the other side of the state from us, so you know this January was kind of normal. We had some cold days; we had some hot days. But in the end, it wasn’t too far off of a normal. Glenn Pruitt Okay, great. I know you’re hesitant to make any additional comments on the strategic alternative discussion, but I was wondering if you could just give some fact space information on what precipitated this discussion? Was it someone approaching you externally or was it initiated internally? Brad Beecher You get the same answer as Paul did – I have no update. Operator Our next question comes from Julian Dumoulin-Smith of UBS. Paul Zimbardo It’s actually Paul Zimbardo in for Julian. Just a quick question, if you could answer whether you believe you’d be subject to regulatory approval in all of the jurisdiction in the event of a change of control? Brad Beecher Yes, we would believe that. Operator Our next question comes from David Frank of Corso Capital Management. David Frank My question was just asked. Thank you very much. Laurie Delano Thank you. Operator Our next question comes from Paul Patterson of Glenrock Associates. Paul Patterson Just on the sales growth, what was weather normalized, I apologize if I missed it, for 2015? Laurie Delano We generally estimate our total normal sales volume to be about 5 million kilowatt hours – I’m sorry, megawatt hours, so we were just under that. Brad Beecher But we continue to believe our weather-normalized sales is right at 5 million megawatt hours, so not a lot of growth in 2015. Paul Patterson Okay. And then, I guess the rest of my questions have been asked. Thanks. Operator This concludes our question and answer session. I would like to turn the conference back over to Management for any closing remarks. Brad Beecher Thank you. Before we close, I remind you that we’re focused on our vision of making lives better every day with reliable energy and service. We’re committed to meeting today’s energy challenges with least-cost resources while ensuring reliable and responsible energy for our customers, an attractive return for our shareholders and a rewarding environment for our employees. Thank you for joining us today and have a great weekend. Operator The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. 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Black Hills’ (BKH) CEO David Emery on Q4 2015 Results – Earnings Call Transcript

Operator Good day, ladies and gentlemen, and welcome to the Black Hills Corporation Fourth Quarter and Full-Year 2015 Earning Conference Call. My name is Kat 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 presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir. Jerome Nichols Thank you, Kat. Good morning, everyone. Welcome to Black Hills Corporation’s fourth quarter and full-year 2015 earnings conference call. Leading our quarterly earnings discussion today are David Emery, Chairman and Chief Executive Officer; and Rich Kinzley, Senior Vice President and Chief Financial Officer. During our earnings discussion today, some of the comments we make may contain forward-looking statements as defined by the Securities and Exchange Commission and there are a number of uncertainties inherent in such comments. Although we believe that our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. We direct you to our earnings release, Slide 2 of the investor presentation on our website and our most recent Form 10-K, Form 10-Q, and other documents filed with the Securities and Exchange Commission for a list of some of the factors that could cause future results to differ materially from our expectations. I will now turn the call over to David Emery. David Emery Thank you, Jerome, and good morning, everyone. Thanks for participating in the call this morning. I will be following along here on the webcast presentation deck for those of you who have it. Starting on Page 3, we will follow a similar agenda to previous quarters. I’ll give a quick update on highlights of the quarter. Rich Kinzley will cover the financial update, and then I’ll jump back in for forward strategy before we take questions from all of you. Moving on to Slide 5, fourth quarter highlights, we had a real solid fourth quarter despite the fact that we had mild weather for our gas utility territories and a continued decline in crude oil and natural gas prices, which affected our oil and gas results. During the quarter, we made great progress on several key growth initiatives, including our pending acquisition of SourceGas. Related to SourceGas, we received regulatory approvals now in three states; Arkansas, Nebraska, and Wyoming. And our closing will occur as soon as we receive approval in the state of Colorado. We still expect to close sometime during the first quarter. We’ve also recently completed our permanent financing on both the debt and the equity needed to close the transaction, so we’re ready from our finance standpoint. We still have several teams working on detailed integration activity. We expect to be fully integrated all systems and processes by year-end 2016, assuming we get closed by the end of the first quarter. Moving on to Slide 6, utility highlights for the quarter, Black Hills Power received final approval from the Wyoming Public Service Commission to begin construction on the first segment of our new 144-mile transmission line that will go from northeastern Wyoming to Rapid City, South Dakota. We expect to start construction in February and have that line completed ad in-service by year end. At Cheyenne Light in Wyoming, we recorded a new winter peak load of 202 megawatts on December 28, 5 megawatts higher than the previous winter peak set the year before. At our Colorado Electric subsidiary, we received approval in October to purchase the $109 million 60-megawatt Peak View Wind project. That project will be built by a third-party wind developer and we’ve executed a build transfer agreement with them, and we’ll take over as soon as the project is in-service, which is expected at year end. At Colorado Electric, we also continued construction on our new $65 million, 40-megawatt simple cycle gas turbine, which we’re adding to the Pueblo Airport Generating Station. We expect that turbine also be in service by year end. Moving on to Slide 7, Non-regulated Energy and corporate highlights for the quarter. On the Non-regulated Energy side, we initiated process during the quarter to explore the sale of a minority interest in our Colorado IPP 200-megawatt combined cycle units at the Pueblo Airport Generating Station. That process is ongoing, and we expect to make a decision related to that potential sale in the first quarter. We also completed our 2014, 2015 Mancos formation shale gas drilling program in the Southern Piceance Basin to prove up, the extent to that resource. We drilled, completed and tested and now have on production nine wells. We have four additional wells that we drilled and cased. We deferred the completion activities on those four wells, because we have a limited amount of gas processing capacity out of the area and we won’t need them probably call, at least, next year to fill the plant capacity. Overall, the results of the drilling program exceeded our expectation, so we’re quite pleased with the results there. On the corporate side, last week, our Board of Directors declared a quarterly dividend of $0.42 a share, that’s equivalent to an annual dividend rate of $1.68. The increase to $0.42 represents the 46th consecutive annual increase in dividends to shareholder. During the quarter, we also entered into $400 million of interest rate swaps to mitigate interest rate risk associated with the future debt refinancing activity, we expect in late 2016 and early 2017. Moving on to Slide 8, this just simply provides a reconciliation of fourth quarter income from continuing operations as adjusted, the fourth quarter 2014 results. Strong performance at our Electric Utilities and Power Generation segments nearly made up for the negative weather impacts at our gas utilities and the low crude oil and natural gas prices that are oil and gas subsidiary that I mentioned earlier. Slide 9 provides a similar reconciliation for full-year 2015 versus full-year 2014. Again, despite the challenges, we’re still able to post an increase in net income as adjusted. Now, I’ll turn it over to Rich Kinzley to talk about the financials for the quarter and the year. Rich? Richard Kinzley All right. Thanks, Dave, and good morning, everyone. We are encouraged to report another year of earnings growth in 2015, driven by strong results at the Electric Utilities, Power Generation, and Coal Mining businesses. As Dave mentioned, overall results were tempered by unfavorable weather and low crude and natural gas prices. Our gas utilities faced warmer than normal weather in the winter heating months in 2015, compared to colder than normal weather in 2014, which contributed to a decline in year-over-year performance, and low commodity prices impacted our oil and gas business. But despite those challenges, we again delivered earnings growth in 2015. On Slide 11, we reconciled GAAP earnings to earnings as adjusted, a non-GAAP measure. We do this to isolate special items and communicate earnings to better represent our ongoing performance. This slide displays the last five quarters, in each of the last two years. In each quarter of 2015, we incurred a non-cash ceiling test impairment charge at oil and gas business, due to the continued decline of crude oil and natural gas prices throughout 2015. In the second quarter of 2015, we also recorded a non-cash impairment of an equity investment at our oil and gas business, due to low commodity prices. In the fourth quarter, we divested this equity investment and realized the small gain above the impaired book value. We also incurred external acquisition-related expenses like financing and other third-party costs, in the second, third, and fourth quarters of 2015 associated with the pending SourceGas acquisition. These impairments in acquisition expenses are not reflective of our ongoing performance and accordingly we reflect them on an as adjusted basis. Our fourth quarter as adjusted EPS reflective of ongoing operations was $0.71 per share compared to $0.77 in the fourth quarter last year. Our full-year as adjusted EPS was $2.98 for 2015 compared to $2.93 for 2014. Fourth quarter and full-year EPS were diluted by approximately $0.04 each due to the 6.3 million share common stock offering we completed in November to partially fund the SourceGas acquisition. Slide 12 displays our fourth quarter revenue and operating income. On the left side of the slide, you’ll note the revenue was lower in 2015, due to reduced revenues at our gas utilities from lower pass-through gas costs during the year, given the low natural gas price environment in 2015. On the right side of the slide, you see strong performance in the fourth quarter at our Electric Utilities and Power Generation businesses more than offset decreased performance at our gas utility, coal mining, and oil and gas businesses, resulting in a 4% increase in consolidated operating income compared to the fourth quarter in 2014 Moving to the full-year on Slide 13, revenue decreased by $89 million, again, due to lower pass-through gas prices in 2015 at our gas utilities. Operating income improved at our Electric Utilities, Power Generation, and Coal Mining businesses in 2015. These improvements were partially offset by lower earnings at our gas utilities due to warmer winter weather and wider losses at our oil and gas business due to the lower natural gas and crude oil price environment. In total, year-over-year operating income increased by over 7%. And excluding our oil and gas business, our core utility and utility-like businesses’ operating income increased by 13%. I’ll touch on each business in more detail in the following slides. Slide 14 displays our fourth quarter and full-year income statements. Before asset impairment charges and acquisition-related expenses, we delivered operating income growth for both the fourth quarter and full-year despite the weather and commodity price challenges mentioned earlier. We implemented cost management efforts early in 2015 and I’m pleased with the way the organization responded. You can see our operating expenses decreased in the fourth quarter and increased only 1.5% for the full-year. Depreciation and interest expense increased, as we continue to grow our asset base. We’ve broken out the non-recurring impairments and external acquisition-related expenses, including the cost of the bridge financing we arranged for the pending SourceGas acquisition. For the full-year, as adjusted EPS grew nearly 2% year-over-year, while EBITDA increased by over 7%. Slide 15 displays our electric utilities gross margin and operating income. The electric utilities gross margin increased in the fourth quarter by $6 million over 2014 and by $49 million year-over-year. These gross margin increases resulted primarily from return on additional investments most notably the $222 million Cheyenne Prairie Generating Station, which went into service October 1, 2014. New rates associated with these investments went into effect at all three of our electric utilities in late 2014 and early 2015. Gross margin also benefited from industrial and commercial load growth in a variety of other factors, as detailed in our earnings press release distributed yesterday. Strong cost management throughout 2015 resulted in reduced O&M in the fourth quarter of 2015 compared to 2014, and a full-year increase of only 5% despite 12 months of the Cheyenne Prairie plant in operation during 2015 compared to three months in 2014. The combination of gross margin improvement and strong cost management resulted in operating income increasing by $7.3 million, or 19% during the fourth quarter compared to 2014, and $36.1 million, or 25% for the full-year 2015 over 2014. The electric utilities had an outstanding year driven by large capital investments to better serve our customers. Moving to Slide 16, our gas utilities gross margin as compared to 2014 decreased $3.6 million in the fourth quarter and $7.3 million for the full-year, driven by 14% fewer heating degree days in 2015 compared to 2014. Both heating seasons comprised of the first and fourth quarters were milder in 2015 than 2014. Strong cost management efforts at the utilities – at the gas utilities with decreases in O&M for both the quarter and full-year compared to 2014, partially offset the negative weather impact. Operating income declined $3 million in the fourth quarter compared to 2014 and by $4.9 million year-over-year. Compared to normal weather, our gas utilities gross margins were negatively impacted by an estimated $4.9 million in 2015. Also, in 2015, our electric utilities gross margins were negatively impacted by an estimated $3.9 million compared to normal weather. Combined these negative weather impacts compared to normal impacted our EPS by approximately $0.13 in 2015. On Slide 17, you see the power generation improved operating income by $3.2 million for the fourth quarter compared to 2014 and by $5.7 million year-over-year. The main drivers in the improved operating income were an increase in megawatts delivered in 2015 due to a Wygen I outage in 2014 and a Wygen I power purchase agreement annual price increases, as well as lower maintenance expenses and general cost management during 2015. For the full-year, as adjusted revenue was $3.5 million higher in 2015 and as adjusted O&M, including depreciation was $2.2 million lower. On Slide 18, our coal mining segment had a $1.2 million operating income decrease compared to the fourth quarter in 2014. For the quarter, revenue was $2.2 million lower as tons sold decreased by 7% compared to Q4 2014, due primarily to planned outages. Further, our regulator approved pass-through mechanism through which we sell approximately half our coal, yielded a lower price per ton in the fourth quarter due to lower mining costs. In Q4, O&M was $1 million lower in 2015 than 2014. For the full-year, coal mining operating income increased by $1.7 million, while tons sold were 4% lower in 2015, due to planned outages we’ve benefited from a significant revenue per ton increase in mid-2014 on a third-party coal contract as a result of a contractually scheduled price re-opener. This contract represents approximately 35% of our production and a higher price per ton increased our revenue in 2015 by $4 million. Keep in mind, the revenue increase from this price adjustment did not drop straight to operating income, as we pay revenue related royalties and taxes on the increase. On the cost side, we enjoyed continued mining efficiencies and lower fuel costs. We moved 31% more overburden in 2015, but at a decrease per cubic yard cost. O&M was flat from 2014 to 2015. Moving to oil and gas on Slide 19, we incurred an operating loss in the fourth quarter of $5.8 million, excluding a $71 million pre-tax ceiling test impairment charge compared to an operating loss of $4.5 million in 2014. Fourth quarter production increased 45% from 2014, driven by a 67% increase in natural gas sales volumes. From an average price received standpoint, including hedges, crude oil decreased by 22% and natural gas decreased by 38% comparing Q4 2015 to Q4 2014. For the full-year, we incurred an operating loss of $27.5 million, excluding pre-tax ceiling test impairment charges of $250 million compared to an operating loss of $11.8 million in 2014. 2015 production of 12.9 billion cubic feet equivalent represented a 29% increase over 2014, driven by a 41% increase in natural gas sales volume with a 10% increase in crude oil volume, and a 24% decrease in NGL sales volume. Comparing 2015 to 2014 average prices received for the full-year, including hedges, natural gas prices decreased by 39% and crude oil by 24%. While we are pleased with the outcome of the drilling program in the Piceance Basin over the last couple years from an operational standpoint, the low commodity price environment in 2015 severely impacted financial results at our oil and gas business. Regarding impairments taken in each quarter of 2015, Slide 20 shows the average trailing 12-month crude oil and natural gas prices, which continued to drop each quarter in 2015, driving the impairments. Given the continued low price environment for crude oil and natural gas, it’s likely we will have additional non-cash impairments to our oil and gas reserves in 2016, at least, in the first quarter. However, any impairments will be much smaller than those recorded in 2015, as our full cost pool is impaired down to approximately $94 million at the end of 2015, with an additional approximate $68 million in excluded costs, which is made up of a certain infrastructure, assets, and wells drilled, but not yet completed. Impairments taken in 2015 are driving down our depletion rate and our current guidance estimates the depletion rate of $0.80 to $1.20 per Mcfe in 2016. It’s worth noting here that we are managing our go-forward exposure in our oil and gas business by cutting CapEx, reducing the cost structure of the business, and beginning to divest non-core properties. You can see in our press release yesterday, the trend in the fourth quarter related to reduced O&M. And as I just noted, we expect a much reduced depletion rate in 2016, given the impairments. Dave will further address our strategy around oil and gas in a few minutes. Slide 21 shows our capitalization. At year end, our debt to cap ratio was 57% with a net debt to cap ratio of just over 50, excuse me, 57% with a net debt to cap ratio of just over 50% given cash on hand. In November, we received net proceeds of $536 million from the issuance of common stock and unit mandatory convertibles to partially fund the pending SourceGas acquisition, which increased our equity and debt. In January, we issued $550 million of long-term debt to nearly complete the permanent financing required for the acquisition. We will be assuming approximately $760 million of SourceGas debt when we closed the transaction. The remaining financing needs at closing expected to be in the range of $50 million to $100 million will be covered with our revolver. We will be more levered than normal on closing of the acquisition, but the strong cash flows and earnings from our businesses will assist us in delevering over the next couple of years. As you know, we continue to evaluate the potential sale of a minority interest in our Colorado IPP facility, which may yield proceeds allowing us to reduce debt. And to help fund our strong future utility focused capital program, we plan to put an at the market equity program in place in 2016. We will prudently issue equity through that program in 2016 and 2017. We are committed to maintaining our current solid investment grade credit ratings and our forward forecasted metrics support those ratings. Slide 22 demonstrates our track record of growing operating earnings and EPS. We look forward to closing the SourceGas acquisition and taking the next step forward in continuing to build upon our impressive track record of growing shareholder value, as we serve our utility customer safely and reliably. Our strong forward utility-based capital program will drive an above average growth profile compared to our utility peers, and the addition of SourceGas will enhance our growth prospects. Moving to Slide 23, yesterday, we updated our 2016 EPS guidance to be in the range of $2.40 to $2.60. This revision updates our previous 2016 earnings guidance issued on November 23, taking into account the additional interest expense associated with our recent $550 million debt issuance. It’s important to note the range does not include any earnings contribution from the SourceGas properties. When the SourceGas transaction closes, we will issue updated 2016, guidance and preliminary 2017 guidance with refreshed assumptions for all our forward-looking activities. 2016 will be a busy year as we effectively manage our businesses, integrate SourceGas and position ourselves for strong earnings growth in 2017 and beyond. I’ll turn it back to Dave now for strategy update. David Emery All right. Thank you, Rich. Moving on to Slide 25, we’ve shown you this slide for quite sometime now. But we group our strategic goals into four major categories and really with the overall objective of being an industry leader in all we do. Those four key objectives are profitable growth, valued service, better everyday, and great workplace. In the profitable growth area on Slide 26, strong capital spending drives our earnings growth. And we forecast total of more than $1.1 billion in capital spending for 2016 through 2018. That projected spending far exceeds our depreciation driving the earnings growth. It’s important to note that this table on Slide 26 does not include any capital related to the SourceGas acquisition. Once that acquisitions close, we’ll provide some revisions to the forecasted capital spending. On Slide 27, we continue to make great progress constructing our new turbine at the Pueblo Airport Generating Station at $65 million simple cycle gas turbine is on schedule and we expect it to be in service by year end 2016. To-date, we’ve spent about $35 million of a total $65 million budget were projected to come in at or under budget. Construction is about 27% complete and notably, we’ve had no safety incidents to-date. On Slide 28, as I mentioned earlier, we received approval from the Colorado PUC in October to purchase the new Peak View Wind Project for our Colorado electric utility. The third-party developer expects to commence construction in the first quarter and achieve commercial operations by year end at which time we’ll take over the project. We have made almost $12 million in progress payments as of December 31. Moving on to Slide 29, as Rich mentioned, our electric utility has demonstrated solid earnings growth in 2015, and a big part of that was our industrial load growth. We’ve had strong industrial load growth in all three of our electric utilities during 2015, for an overall increase in industrial load of almost 15%. That growth has been from several different industrial customers, but the datacenter load growth particularly in Cheyenne Wyoming is the most notable driver of that growth. Slide 30, another significant growth opportunity we’re pursuing very actively is the utility cost of service gas supply program. We’ve been talking about this for well over a year now. Under a cost of service gas program, our direct investment in natural gas reserves will provide long-term price stability for our customers, while also providing opportunities for increased investment and earnings for shareholders truly a win-win scenario. We submitted cost of service gas regulatory filing this fall in six separate states. Hearing dates have now been set in all six of those states. And we’re currently in the process of evaluating producing properties and drilling prospects for inclusion in the program that includes our Mancos Shale gas properties in the Piceance Basin in Colorado, which we’re evaluating now that we’ve finished up our test drilling program there. We hope to finalize our cost of service gas program sometime before year end 2016. Moving on to Slide 31, oil and gas strategy, Rich referred to this a little bit earlier. But we previously announced our plan to transition our oil and gas business to primarily support cost of service gas within our utilities. That program will provide stable price, low-cost fuel to our utility customers. As noted earlier, we completed our 2014/2015 Mancos Shale gas drilling program and essentially helped us prove up the magnitude of the resource we have in the Southern Piceance Basin. As Rich noted, we dramatically reduced our planned oil and gas capital spending for 2016 and 2017. Current product prices just simply don’t support additional capital investment in oil and gas. And our plan for capital going forward is essentially putting our capital investment into our cost of service drilling program. We’ve reduced our staff and cut cost in order to reduce our ongoing O&M. And our professional staff at our oil and gas subsidiary is busy applying their expertise and knowledge to assist our utilities with execution of cost of service gas. Moving on to Slide 32, this slide just simply provides a well by well details for our Mancos drilling program. It includes all the wells we’ve drilled now from 2013 through 2015. As I said earlier, overall we are very pleased with the results of the program little better than we expected. Moving on to Slide 33, I mentioned earlier, our dividend increase, we continue to be very proud of our dividend track record. And this is now being our 46th consecutive year of dividend increases for shareholders that’s one of the longest strings in the utility industry, and a record we’re very proud of. Slide 34, Rich talked earlier about our solid investment-grade credit metrics. We do have a solid balance sheet and good investment-grade credit ratings. Long-term, we expect the SourceGas acquisition to be credit positive, adding substantial low-risk, predictable cash flows to our credit metrics. On Slide 35, it illustrates the focus we place every day on operational excellence and on being a great workplace. During 2015, our safety record and our electric reliability performance were both near the top of the industry, that’s something we strive for an essentially all we do. On Slide 36, this is our scorecard, again, our way of holding ourselves accountable to you, our shareholders. Every year, we set forth our key strategic goals and initiatives and literally check the box on progress as we proceed throughout the year. Slide 36 is our 2015 goals and progress we’ve made towards those goals. Slide 37 is a preliminary scorecard for 2016. This includes the goal of completing the SourceGas transaction, but does not include any specific goals related to SourceGas. Once we require those properties, we will update the scorecard. That concludes our remarks. We would be happy to entertain any questions that anyone might have. Question-and-Answer Session Operator Ladies and gentlemen, we are ready to open the lines for your questions. [Operator Instructions] And your first question comes from the line of Insoo Kim with RBC Capital Markets. Please go ahead. Insoo Kim Hey, good morning, everyone. David Emery Hey, good morning, Insoo. Insoo Kim First question on the oil and gas strategy. I know you’ve talked about the low commodity price environment, and how the potential sale or divesting of the non – some of the assets would not result in the value that the asset that you don’t have. Just given the ongoing cost of service gas program, if that doesn’t go through, what are your thoughts regarding that business and the timing of such a strategic decision? David Emery Well, I think we have a pretty degree of confidence that we will have our cost of service gas program, the specifics of the size and which states choose to participate and at which levels, I think is the primary question in our mind, we think it’s a program that makes tremendous sense for customers and shareholders alike. And I think we’re uniquely positioned for that program because of our oil and gas expertise. Strategically, we’ve talked about divesting our non-core properties there. We’ve made the statement that we don’t intend a fire sale those if you will. But we are taking our time and making sure we can divest of those in a way that makes sense for us, and really focusing almost all of our attention on cost of service gas, whether that’s our Manco’s program and the shale gas resource we have in the southern Piceance Basin, or whether that would be reserves that we could potentially go out and purchase or a combination of the two, that’s really what we’re working on right now. We can’t finalize any of those plans or decisions until we know what size program we will have going forward, which of course is dependent on the regulatory process. Insoo Kim Got it. And sticking to cost of service gas, the CapEx estimates that you guys have through 2018 for that program. Is that still more of a placeholder for now, until you know what the details of the program are and the level of investments that you’ll be needing? David Emery Yes. Essentially, the way we came up with those numbers as we assume that we would commence a drilling program kind of late in 2016. We’ve talked about kind of our rough ongoing run rate for horizontal drilling program is around a $100 million for a rig running continuously for a full-year. And so that’s really where those numbers came from. We’ve got some wells, we have yet to complete in the Piceance and so the 2016 number is a little lower and then we basically assume a drilling rig year, if you will, for both 2017 and 2018, which I think is a pretty realistic assumption assuming we get the program off the ground. Insoo Kim Got it. And turning to the utilities business, for the legacy Black Hills utilities, ex-SourceGas, I guess beyond 2016 timeframe, what are some of the projects that you are looking for that could drive – further drive rate-based growth? David Emery Well, we’ve got several things we’re working on. In our slide deck, we do list a list – listing of kind of major utility projects. We break those out back in the appendix. And there’s several transmission projects, natural gas pipeline project, and other things that we’re actively pursuing right now. The other thing that we’ve talked about is, we’re short resources on the generation side and we talked about that in our Analyst Day back in October. We’re just getting started really on revisiting our resource planning for our electric utilities and fully expect that out of that, we’re going to need some additional resources to meet the load growth that we’re experiencing. Insoo Kim Got it. And just last question on – for the electric utility or I guess the electric or gas utility rate load growth, how much of your load growth is dependent on oil and gas customers? I’m assuming it’s relatively small, but – and what kind of impact have you seen, if at all, due to the low commodity price environment? David Emery Yes, essentially none of our load growth is dependent on oil and gas a very, very small percent. We don’t serve on the electric side direct oil and gas producing basins. So we get a small amount of kind of peripheral businesses that are located near the producing basins, but it really doesn’t drive a lot of growth a little bit and very light industrial and commercial load that we have – we do have one oil field that we serve at Black Hills Power had a little bit of load growth there it’s an enhanced oil recovery project. And I would say the prices there on a marginal cost basis are sufficient to keep producing. And so we really haven’t seen any cut backs in production, which would impact our load there. So a pretty minimal overall exposure to oil and gas prices on the electric utility side. Insoo Kim Got it. okay, thank you very much. David Emery You bet. Thank you. Operator Thank you. [Operator Instructions] Our next question comes from the line of Chris Ellinghaus with WillCap. Your line is open. Chris Ellinghaus Hey, guys, how are you? David Emery Good. Good morning, Chris. Chris Ellinghaus You quoted a $0.13 drag from weather for the year, I assume that’s versus 2014? David Emery No, that’s versus normal weather, Chris. Chris Ellinghaus Okay, great. David Emery And actually a little bigger than that compared to 2014, because 2014 was a little colder than normal. Chris Ellinghaus Okay. And can you give us any kind of characterization of how January went for the service areas? David Emery That are pretty close, but normal weather maybe slightly warmer than normal depending on the territory. Chris Ellinghaus Okay. And can you give us a little more detail on where the industrial strength is coming from? David Emery Yes, we’ve got several things, I mean, a lot of it is related to data center load growth in Cheyenne and Wyoming and then that’s the over warming portion of it. Colorado, some of our industrial businesses there have been growing at a steady clip, particularly gold mining has been real strong. There’s also an old munitions depot down in Pueblo, where they’ve ramped up load as they dispose of old weapons, and expect to keep that higher load for multiple years as they go through that process. Black Hills Power, we’ve just seen some of our industrial customers, whether that’s crude oil refining, I mentioned the oilfield earlier a combination of several of those things have helped expand load at Black Hills Power as well. Chris Ellinghaus Okay. And can you give us some ideas about when your next IRPs will get filed? David Emery Probably going to be late this year, or early next year. Chris Ellinghaus For all? David Emery Yes. Chris Ellinghaus Okay. David Emery We typically do our research planning for Cheyenne Light and Black Hills Power jointly. We manage that as essentially a single load, they’re interconnected systems, and we combine our resource planning efforts for those two. Colorado Electric, of course, we do separately. Chris Ellinghaus Okay. And do you have any planned major outages for this year or next year? David Emery We don’t have anything, I don’t think there’s any real lengthy outages. The ones we do have planned are incorporated into our earnings guidance. Chris Ellinghaus Okay. And do you have any updated thoughts on the Colorado SourceGas approval situation? David Emery No, I think we’re pretty well positioned there. We were successful in reaching a settlement. Colorado has a process, where your settlement is reviewed by an Administrative Law Judge and then the Commission requires a little time to review the recommendation of the ALJ and issue its order. We don’t foresee any real problems there. We are just kind of going through the motions, if you will, waiting for the process to play itself out. Chris Ellinghaus Okay. Thanks for the color, guys. David Emery You bet. Thank you. Operator Thank you. And our next question comes from the line of Andy Levi with Avon Capital Advisors. Your line is open. Andy Levi Hi. Good morning. David Emery Good morning. Andy Levi How are you? David Emery Great. Thanks. Andy Levi Just two questions, maybe three. But just the first one just on the IPP sale process. Can you just give us a little more color on that kind of I guess, it’s taking a little bit longer than you thought, so just kind of what’s going on there, and when we may hear something from you on that? David Emery Yes, I don’t know if it’s really taking a whole lot longer than we thought it would. We knew announcing kind of pre-holidays is not an ideal time to get things done expeditiously. The process is going well, obviously, we’ve engaged an investment banker. We’re going through the bidding process. We’ve had very strong indication of interest from multiple bidders. When you we are kind of working our way through the process. And I didn’t say earlier, we still expect to make a decision sometime before the end of the first quarter. Andy Levi Okay. And any reason to think that a sale wouldn’t happen, or that’s probably unlikely? David Emery Yes, I think it just really comes down to value. As I said, so far, indications have been pretty strong. But when you get down into negotiating real specifics and details and selecting final bids, you never know until you’re done. But we’re certainly encouraged by what we see so far. Andy Levi Okay. And then on the oil and gas segment, I just wanted to kind of understand what we got left on the books. I mean, I guess you showed $209 million of book value right at the end of December. Is that correct on page 20, I think it is? David Emery Correct. Andy Levi Okay. David Emery Yes, so… Andy Levi Can you give us a breakdown on the $209 million kind of… David Emery Sure. Andy Levi …how much is commodity related and how much is kind of, I don’t know hardware or kind of steel and the ground type stuff? Richard Kinzley Yes, as I pointed out in the comments earlier $94 million of that’s our full cost pool. So it’s the wells that are in our pool. $68 million is in unevaluated properties, which includes some infrastructure. And then wells – Dave mentioned that we drilled for wells in the Piceance, but didn’t complete them. So they are in that pool. And then you’ve got the balance, which is roughly $40 million which is the other assets of the business. Andy Levi Okay. So just to understand the commodity exposure piece is, what would you estimate? So if you kind of take out the pipeline stuff and trucks and things like that, what do you…? Richard Kinzley Say $150 million or $160 million is what’s left on the books, roughly exposed. Andy Levi Okay, okay. And then I know you commented on it, but I don’t think I was listening too closely. How much of that $150 million are you trying to get into rate-based gas? Or is that – is it not that defined? Richard Kinzley Really not defined at this point as Dave, mentioned a bit ago we’re evaluating whether a purchase of a third-party property or our existing gas assets make sense for that Cost Of Service Gas program, and working through that with regulators. Andy Levi Okay. What was the thing on the third-party? I’m sorry? Richard Kinzley Well one of the things we’ve evaluated in a way to potentially jumpstart our program if you will is assuming we get approval for Cost Of Service Gas if we could find a gas producing property perhaps with a distressed buyer or distressed seller. We might have an opportunity to buy a property in addition to looking at some of our properties primarily just the Mancos property is the one of our own really is a good viable long-term gas resource in at least the couple of trillion cubic foot resource potentially as much as 8 and that’s the one property. We have, we think would be a great fit for Cost Of Service Gas. But we’re also looking and if we can opportunistically purchase reserves from other parties we would like to do that to contribute to the program as well. Andy Levi Okay. And then – and I lied about the three questions. But in your guidance that you gave for 2016, the temporary guidance without SourceGas, what’s the – how much is oil and gas? What’s the drag? Richard Kinzley Well we haven’t broken out segment guidance like that yet when we get the SourceGas deal closed we intend to issue updated 2016 guidance and preliminary 2017 guidance and we may provide a little more color at that point around. Well certainly we’re going to provide updated assumptions on all our forward-looking activity including oil and gas, but we may provide a little more color at that time. Andy Levi I mean I guess the kind of way I looked at it is – and I think we’ve probably discussed this in the past – is that you have this really good story at the utility; the IPP is good and stable, you sell a portion of that. And the coal – mine math coal obviously is stable as well. So you have this really good kind of growth story at the utilities, especially with SourceGas. And then you have this distraction of this oil and gas business, which I understand you’re trying to get into rate base, for no better way to put it. But if, for some reason, a majority of those assets or the rate-basing of gas doesn’t materialize for whatever reason, what’s the longer-term strategy on this? Is it just to kind of sell it, or to kind of continue on? Again, this is assuming that commodity prices stay where they are, which I have no idea where they are going. But just kind of what your thinking is on that, because you have written down the majority of it, but it is a distraction and is a drag on earnings, and then ultimately valuation. So, without that drag, let’s just say it’s $0.25 to $0.40. You can kind of do the dumb math on a P/E basis, and you’ll come up with a higher valuation for the stock? Richard Kinzley Yes, I talked about this a little bit earlier, but I mean I think we fully expect to have a Cost Of Service Gas program going forward. The size of that and which states choose to participate at what level of production every year is really the question that we think it makes great sense to have a program. We think that we’ll be able to convince the regulators of the benefits to customer of having a program. There are tremendous benefits for customers in implementing a program, so we’re pretty confident we will have a program. And as we’ve said our strategy is to utilize that business to support Cost Of Service Gas. We’ve essentially eliminated any capital spending related to non-cost of service gas oil and gas investment. We’ve cut our staff, we’ve cut our ongoing operating expenses, we have the professional staff focused on Cost Of Service Gas. And as far as the other non-core properties we’ll continue to look for opportunities to divest those. We’re not just throwing our hands up and dumping them, but we’re going to sell them as prudent carefully review properties and sell them to people who it make sense to sell them to and gradually clean up the non-core properties, if you will. As far as ongoing earnings and the impact of ongoing earnings, when you look at the amount we impaired in 2015, the drag on earnings is going to be dramatically less than 2016 than it was in 2015. Just because we wrote off almost $250 million of our pool, and we’re not spending additional capital. So a depletion will be lower and then as we mentioned the cost structure is lower, so the drag will not be anywhere near what it was in 2015 and 2016. Andy Levi So on a clean basis, absent the write-downs, how much was the drag in 2015? Richard Kinzley Well, operating loss you can see in a press release was $27 million. Andy Levi Okay. So $27 million. We’ll use, I don’t know, 51 million shares to try and keep it kind of where it’s at. That was about $0.53 a share, or something like that on the new share count, absent the dilution from the converts, right? Is that right? So is there any type of guidance you can kind of give us? Richard Kinzley We’ll give updated guidance when we get the SourceGas deal closed. But basically 240 to 260 incorporates the assumptions we put out on November 23 guidance, incorporates the full drag of the equity, converts, and interest associated with the debt we just placed, and it doesn’t count any income contribution from SourceGas. So it’s a temporary number. Certainly, when we get SourceGas closed, I would expect 2016 to be higher than that, and then we’ll issue updated assumptions at that time. Operator Thank you. Our next question comes from the line of Tim Winter with Gabelli & Co. Your line is open. Tim Winter Good morning and thanks for taking my question. I wondered on the 2016 guidance, I have two questions. One is, what are you guys assuming for the IPP plant? Is there any earnings in there? And then the second part is, can you give us any updated metrics on SourceGas, maybe rate-based, ROE, earnings, anything like that that maybe just ballpark ranges? Richard Kinzley Repeat the first part again, Tim, on the IPP? You repeat the first question on IPP. Tim Winter What’s the assumption in the 2016 guidance for the…? Richard Kinzley Right now I assume that we own it for the full- year. Tim Winter Okay. Richard Kinzley And then on the metrics for SourceGas, again, we’ll put some color on that when we get the deal closed. Tim Winter Okay, okay. Thank you. Operator Thank you. Our next question comes from the line of Tom Nowak with Advent Capital. Your line is open. And I’m showing no further questions at this time. I’d like to turn the call back to David Emery for any closing remarks. David Emery All right. Well, thank you, everyone, for your participation this morning. We appreciate your continued interest in Black Hills. Have a great rest of your day. Operator Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day. Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. 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