Black Hills Corporation (BKH) Q2 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation Second Quarter 2015 Earning Conference Call. My name is Matt, and I’ll be your coordinator 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.

Thank you, Matt. Good morning, everyone. Welcome to Black Hills Corporation's second quarter 2015 earnings conference call. Leading our quarterly earnings discussion today are David Emery, Chairman, President 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 and Form 10-Q filed with the Securities and Exchange Commission for a list of some of the factors that could cause future results to differ materially from our expectations. I will now turn the call over to David Emery.

Thank you, Jerome, and good morning everyone. I will be starting on Slide 3 of the webcast deck for those of you who are following along. This quarter we’ll follow a similar format to previous quarters. I'll give a quick update on the quarter, Rich Kinzley, our CFO will provide the financial update for the quarter, and then I’ll speak to strategy going forward followed finally by a question-and-answer session. If you would turn to slide 5 second quarter highlights we had an exciting quarter. In the second quarter we posted strong earnings growth, and EPS as adjusted compared to last year, almost a 22% improvement. We announced the signing of an agreement subsequent to the end of the quarter to acquire SourceGas and that will be the largest transaction in the company’s history. We also closed on the $17 million purchase of a natural gas utility in Northwest Wyoming and I think notably related to that acquisition, that utility was fully integrated into all of our systems on day one following the closing of the transaction. On the business environment side from a weather perspective we have moderate weather in our utilities service territories this year compared to colder than normal weather in the same period last year and that tempered the results slightly from both our electric and gas utilities. Highlight from our utilities, The Black Hills Power received approval from the Wyoming Public service commission for a CPC and to construct a new 144 mile, $54 million electric transmission line from Northeast Wyoming to Rapid City, South Dakota. If you recall last year the South Dakota PUC also approved the same line and we expect construction to commence in the fourth quarter of this year. Cheyenne Light, Fuel & Power recorded a new all-time peak electric load of 212 megawatts, on July 27, it was a third new peak since the 1st of June. Our previous peak was last year at 198 megawatts last July. The new peak represents a 7% increase in peak load in just a little over one year highlighting the strong growth in our Cheyenne service territory. Slide 6 a continuation of utility highlights. Our Colorado Electric Utility commenced construction on a $65 million, 40 megawatt, simple cycle combustion turbine at the Pueblo Airport Generating Station. We expect the commercial operation there in the fourth quarter of next year. That turbine will replace the capacity lost when we retired the 42 megawatt coal fired Clark Station in Canyon City Colorado in compliance with the Colorado Clean Air-Clean Jobs Act. Colorado Electric also filed their request on June 23 with the Colorado PUC for a CPCN to acquire a 60 megawatt wind project, the Peak View Wind Project which is going to be located near our Busch Ranch wind farm. That project was originally submitted in response to an all-source RFP that we did in May 2014. The commission rejected those bids, we basically went back renegotiated and resubmitted that proposal. A third party developer will build the project and we expect the commercial operation in the fourth quarter of next year and assuming we receive approval from the Colorado Commission, Colorado Electric Utility will purchase the project for a little over $100 million upon commercial operation. Slide 7, non-regulated energy highlights. We are currently drilling the last of 13 horizontal Mancos Shale wells as part of our 2014, 2015 drilling program in the Southern Piceance Basin in Colorado. Completion activities for three wells are underway and we are now fracking the third well on a three well pad, the other two have already been treated and we expect to place those three wells on production in September. Results for the overall program continue to meet or exceed our expectation. Also related to oil and gas, we reduced our forecasted capital spending for 2016 and 2017 by a total of about $215 million due to our expectation of continued low oil and gas prices. I’ll speak more about that spending reduction later, but it certainly has positive implications for the financing of our SourceGas acquisition. Highlights at the corporate level, we declared a quarterly dividend of $0.405 a share which is equivalent to an annual dividend rate of a $1.62 at our recent Board meeting last week and on June 26, we extended our $500 million unsecured revolving credit facilities on similar terms. That facility now has a maturity date of June 26, 2020. And finally our corporate wide cost containment efforts are on-going and at least partly successful in helping mitigate the impacts from our low commodity prices and the weather. Moving onto slide 8 the second quarter financial highlights. We earned $0.56 per share as adjusted during the quarter, 22% increase compared to the same quarter last year which was a fantastic result especially considering the low oil and gas prices and moderate weather. Slide 9 provides a reconciliation of our second quarter 2015 income from continuing operations as adjusted to second quarter 2014 results. Strong performance in nearly all of our businesses especially the electric utilities more than made up for poor performance at our oil and gas business. Now I’ll turn it over to Rich Kinzley to talk about the financial highlights for the quarter, Rich.

All right, thanks Dave, and good morning. As Dave mentioned our core utility and utility like businesses continue to demonstrate strong performance. In the second quarter as you saw on slide 9 each of the businesses improved financial performance compared to the second quarter of 2014. In particular electric utilities posted strong operating results and low commodity prices continue to impact oil and gas business, but despite that challenge we posted a great quarter. On Slide 11 we reconciled GAAP earnings to earning as adjusted, a non-GAAP measure. We do this to isolate special items and communicate earnings to better indicate our ongoing performance. In the first two quarters of 2015 we reported non-cash ceiling test impairment at our oil and gas business and in the second quarter of 2015 we had an impairment of an equity investment at our oil and gas business. These impairments were due to continued low natural gas and crude oil prices and were non-cash charges that are not reflective of our on-going operational performance. We also incurred acquisition cost in the second quarter of 2015 related to the SourceGas acquisitions which were non-recurring in nature. Our second quarter EPS as adjusted reflective of ongoing operations was $0.56 per share compared to $0.46 per share in the second quarter last year. Our trailing 12-months EPS as adjusted was $3.02, a 10% increase over $2.74 reported for the 12-months ended June 30, 2014. Moving to slide 12, we incurred $66 million in after-tax noncash impairment charges related to our oil and gas holdings in the second quarter. While performing our ceiling test calculation for our oil and gas reserves at the end of the second quarter we determined calculations of this test in prior periods were an error. The error related to evaluated, evaluating and correctly accounting for all tax impacts associated with the calculation. As a result, we recalculated our ceiling test impairments and associated impacts to depletion expense for each period back to 2008 as well as the associated impact to the gain from the sale of our Bakken properties in 2012. In short, we understated ceiling test impairment charges in 2008, 2009, 2012 in the first quarter of 2015. An order stated depletion expense in all previously reported periods after 2008. We also understated the gain on the Bakken sale in 2012. When we file our second quarter 10-Q later this week, we will also file our 10-K/A for 2014 and 10-Q/A for the first quarter of 2015. Both amended filings will reflect the revised numbers associated with this issue. You will see in the 10-K/A and 10-Q/A that the revisions to prior periods are all noncash in nature and not meaningful to our ongoing financial performance. Operating earnings as adjusted and EPS as adjusted for each of the periods from 2012 through the first quarter of 2015 increased slightly from previously reported amounts as we previously overstated depletion expense. Slide 13 displays our first quarter revenue and operating income. Strong performance at our core utility, coal mine and Power Gen businesses more than offset decreased performance at oil and gas. While revenue was down slightly in 2015 due to lower revenues at our oil and gas utilities from lower pass through gas cost in 2015, second quarter 2015 operating income increased nearly 19% over 2014. Slide 14 displays our second quarter income statement, comparing Q2, 2015 to Q2, 2014 you will note a 9% increase in gross margin, the majority of which came from our electric utilities. Operating expenses increased only at an inflationary level despite the added cost associated with the October 1, 2014 in service of the $222 million Cheyenne Prairie Generating Station. Depreciation and interest expense increased primarily due to the additional plant inservice and additional borrowings associated with Cheyenne Prairie. EPS as adjusted grew 22% year-over-year and EBITDA increased by 15%. Slide 15 displays our electric and gas utilities gross margin and operating income. We've changed from discussing revenue to gross margin at our utilities as we feel gross margin is more relevant to understanding ongoing results since revenue includes the fuel pass through cost. On the left side of the Slide you will see our electric utilities 2015 second quarter gross margin increased by $16 million from 2014. This increase was driven primarily by additional return from investments in our generation facilities from completed rate cases in late 2014 and early 2015 in Colorado, South Dakota and Wyoming. Gross margin also benefited from higher commercial and industrial demand. Operating income during the first quarter for electric utilities improved $11 million or 37% year-over-year as a result of increased gross margin and solid cost management. Operating expenses including depreciation increased only 4.8 million year-over-year despite the addition of Cheyenne Prairie. Looking to the right side of the Slide 13, our gas utilities gross margin decreased by $0.5 million, mainly due to milder weather in 2015 compared to 2014. Second quarter 2015 heating degree days in our electric utility service territories were 14% below 2014 and 10% below normal. Despite decreased gross margin second quarter 2015 operating income increased $1.3 million compared to 2014 due to lower bad debt and strong cost management with reduced operating expenses by 2.6 million year-over-year. Depreciation increased by 800,000 due to increased plant in service. Overall across our electric and gas utilities weather impacts to gross margin in the second quarter were $1.3 million negative compared to the prior year and $1.4 million negative compared to normal. On Slide 16, you will see Power Gen’s operating income improved by $700,000 compared to 2014. Power Gen benefited from annual power purchase agreement price increases offset by decreased capacity payments since we sold the 40-megawatt CT2 to the City of Gillette in the third quarter of 2014. We operated this facility on behalf of the city and the lost revenues from no longer receiving the capacity payments were partially offset by our sharing of the savings we create for the city via economy energy purchases rather than running the facility. Cost management efforts at Power Gen allowed us to reduce operating cost slightly year-over-year. On the right side of slide 16 coals mining saw operating income improve in the quarter by $1.5 million from 2014. Our average coal price received increased 13% comparing Q2 2015 to Q2 2014, the result of a significant increase in July 2014 in the price per ton on the third party contract. This contract represents approximately 35% of our production. Tons sold were up slightly year-over-year, operating cost increased on major maintenance items and higher royalties due to increased revenue. Moving to oil and gas on slide 17, you’ll see we sustained a $7.5 million operating loss for the quarter. Commodity prices significantly impacted results in the second quarter of 2015 as our average received prices including hedges were down 17% for crude oil and 44% for natural gas compared to the second quarter of 2014. Overall, second quarter production increased 32% compared to the same period in 2014 driven largely by a 47% increase in natural gas production. We brought on three new Mancos Shale wells in the first quarter and they continue to perform solidly from a production perspective. On the cost side, Q2 O&M expenses increased slightly comparing 2015 to 2014 due primarily to water haulage cost and higher lease operating expenses on non-operated wells. DD&A increased $2.2 million compared to 2014 due to higher production volumes. Sequentially production from first quarter of 2015 to the second quarter of 2015 increased 20%. Low commodity prices will likely continue to hamper our oil and gas financial results in 2015. As I mentioned earlier we incurred an impairment charge in the second quarter and will likely incur additional impairment charges later in 2015 if crude oil and natural gas prices remain at current depressed levels. However, we continue to be pleased with the momentum we have, improving up our Piceance Mancos Shale play. We expect to substantially complete our drilling, completion and testing program in the Southern Piceance as we work through 2015. We also substantially reduced our expected capital spending in our oil and gas segment for 2016 and 2017, and Dave is going to talk a little bit more about that here in a few minutes. Slide 18 shows our current capitalization. At quarter end our net debt to capitalization ratio was 54.6% an increased from March, 31st driven by a reduction in equity due to the non-cash impairment charge. Given the expected cash flow from operations for the remainder of the year and our revolver capacity, we have ample funding available for planned CapEx and dividends through 2015. Reduction in 2016 and 2017 spending at oil and gas will help reduce the amount of equity we need to issue for SourceGas acquisition. Dave is going to discuss the SourceGas acquisition here in a moment, but I’ll note, we plan to finance the acquisition in a manner supporting our strong investment grade ratings. Moving to Slide 19, in our earnings press release yesterday we reaffirmed our 2015 earnings guidance range of $2.80 to $3 per share. Given the expectation of continued low crude oil and natural gas prices in 2015, we implemented cost control measures early in the year and expect to continue these efforts through 2015 to achieve earnings in this range. This estimated range is for EPS as adjusted and excludes special items. Slide 20 demonstrates our strong earnings growth performance over the past six years. Our second quarter results demonstrate the continued strong operating performance in growth characteristics of our core businesses. While low crude oil and natural gas prices impacted our oil and gas segment results in the first two quarters. 2015 is a transitional year for our oil and gas business as we work to prove out our Piceance Mancos Shale reserves and we will continue to operate all our businesses as efficiently as we can. And I’ll turn it back to Dave now.

All right thank you Rich. Moving on to strategy, on slide 22, you’ve seen this before. We group our strategic goals into four major categories with the overall objective of being an industry leader in everything we do. Those four major goals for us include profitable growth, valued service, better every day and great work place. On slide 23, subsequent to the quarter end we announced our agreement to acquire SourceGas Holdings LLC for a total consideration of $1.89 billion, that is and will be the largest transaction in our company’s history. We’re excited about that opportunity. It provides a lot of benefits to us, customers and shareholders. It expands our utility presence in Colorado, Nebraska and Wyoming. Also adds the new state for us, the Arkansas which has a fast growth service territory. We’re excited about entering a new state in Arkansas. It increases our customer base by 55% and most importantly it enhances the future growth potential of our utility, and it will be meaningfully accretive to EPS in the first calendar following closing. We expect to file for all necessary approvals next week and anticipate closing in the first half of 2016. Slide 24 provides an illustration of the combined company footprint. Following closing we serve a total $1.2 million electric and natural gas utility customers and 790 communities and eight states. Moving on to slide 25, strong capital spending drives our earnings growth. We forecast the total of $1.2 billion of investment from 2015 to 2017 with nearly $493 million for 2015. Our projected capital spending far exceeds depreciation driving our earnings growth. It’s important to note on this table that it does not include any capital related to the SourceGas properties. Once we close the acquisition we’ll add those into the schedule. Also since last quarter’s call we’ve revised forecasted spending in three areas, and I’ll now briefly point those out. On the gas utility side, we reduced our capital by over $13 million for what we called our Northeast Nebraska pipeline project. That project has been delayed and definitely it was going to serve an oilfield tubular plant in Norfolk, Nebraska and that plant has been put on hold for obviously reasons related to oil and gas pricing. The cost of service gas line, we’ve increased the capital for 2016 and 2017 as essentially we migrate our oil and gas strategy from our straight-up E&P spending that we’ve done in the past more towards cost of service gas program for our utilities. And then finally on the oil and gas line, we’ve increased spending slightly for this year which I’ll talk about and then the decrease for 2016 and 2017 which we already mentioned. On slide 26 as I mentioned earlier we did commence construction on our new $65 million 40 megawatt gas turbine for our Colorado electric utility that is being constructed now at the Pueblo Airport Generating Station, again we expect that plan to be in service in the fourth of next year. We do have a construction financing rider in place for that plant. Moving on to slide 27, that provides an update related to our oil and gas strategy. We remained very focused on finishing our 2014 and 2015 drilling program to prove up the value of our Mancos Shale properties in the Southern Piceance Basin. As I said earlier, overall results of that program continue to meet or exceed our expectation. We’re currently drilling the last of 13 horizontal Mancos wells. Two of the three drilling rigs that we were operating last quarter have been released and we will release the third drilling rig once this final well is cased and cemented. Then we’ll turn our attention to completing the wells. We’re currently completing three wells on our Homer Deep unit 9-11 pad. We’ve completed fracs on our first two wells. And we’re now fracking the third well. Yesterday we pumped Stage 13 out of a planned 48 stages on that well. Once we finish that frac we expect to place those three wells on production in September. If you recall, we’re production limited 20 million cubic feet a day from that area essentially due to the capacity of so much gas processing plant in the areas. So we’ll have to shut in the three wells from our Homer Deep unit 9-41 pad that we placed on production in February in order to make room for the three new wells and get those tested beginning in September. Following the 9-11 pad, we plan to move to our Whittaker Flats pad, another three well location and begin fracking those wells in September and expect to place them on production sometime probably before late November. In light of the low natural gas prices and also combined with the gas processing plant capacity issue that I just talked about, we plan to differ completion of the four-well pad Home Deep unit 7-23 location, that’s where we’re currently drilling that last well. We plan to defer those completions until 2016 or early 2017 when we can include those wells in a cost of service gas program for our utility. Based on what we know today from the first wells we’ve drilled there we won’t need well test from these four wells to finalize our assessment regarding the future economic viability of the Mancos play. It’s better to defer the capital rather than spend it today when we can’t produce the wells anyway. We’ve increased our projected 2015 oil and gas capital spending to a total of $179 million which is up from $167 last quarter. With this change if you go all the way back to the end of last year, we’ve increased our plan 2015 spending from $123 million to $179 million. We talked about several of those factors last quarter but I’ll reiterate them again. There’s several factors that contributed to the increase. The first one is approximately $50 million and carryover from our 2014 drilling program. That was for planned activities in the Mancos and other areas that we didn’t complete in 2014 and made the decision to go ahead and finish in 2015. We also had an increase of another $35 million for non-consent working interests. Other working interest owners elected not to participate in the drilling of the wells we proposed particularly in the Mancos play. And then those two increases are partially offset by the plan deferral of about $30 million which I just talked about related to completing the last four Mancos wells on the Homer Deep units 7-23 pad. And finally, as I mentioned earlier, our expectations for oil and gas prices over the next couple of years don’t support drilling unless that drilling is part of a long term utility cost of service gas program. So as a result of that we’ve reduced our planned oil and gas capital spending by total of $215 million for 2016 and 2017. Moving on to slide 28, that provides well by well detail for our Mancos drilling program. As in previous quarters that includes all wells going back to 2013 through 2015. I’ll give you a quick update on each of the pads highlighted there. The Homer Deep unit 9-41 pad, those wells replaced on production on February. As I said we’ll have to shut those in September to make room for testing additional wells. The 9-11 pad again we’ve fracked two wells. We’re fracking the third now. Those three wells will be tested beginning in September. The 7-23 pad is the one we still have a drilling rig working on. Three wells have been drilled, cased and cemented. We’re drilling the horizontal lateral on the final well, at a little over 490, 500 feet or so today with the plan total depth of about 17,600 feet. On the Whittaker flats pad we’ve drilled cased and cemented three wells. We will begin completions, fracking of those wells in September, again with plans to put them on production for testing in November. Slide 29 is a map illustrating our ongoing activity for the Mancos play. You’ve seen this before. And then on slide 30, we continue to talk about this significant growth opportunity that we are pursuing related to a utility cost of service gas program. Under utility cost of service gas program our direct investment in natural gas reserves will provide longer price stability for our customers while providing increased earnings opportunity for shareholders, truly a win-win scenario. We’re continuing to have very productive regulatory dialogue throughout our service territory meeting with PUC commissioners, staff and consumer advocates. We had several more meetings during the quarter and they continue to go well. We’re working on state regulatory applications and the supporting materials for those with the intent of filing for approvals yet this fall. We’re also still evaluating producing properties and drilling projects for inclusion in the program including our Mancos Shale gas property. As I noted on slide 25, we have revised our capital expenditures related to the cost of service gas program for 2016 and 2017 increasing those numbers to $50 million in 2016 and $100 million in 2017 basically recognizing that our planned oil and gas drilling and related activity will likely be occurring in a cost of service gas program rather than our normal E&P drilling project. Moving on to slide 31, we continue to be very proud of our dividend track record. We’ve increased our annual dividend to shareholders for 45 consecutive years. One of the longest streaks in the utility industry and one we’re very proud of. On slide 32, excuse me, we have strong balance sheet and solid investment grade credit ratings, all three rating agencies reacted favorably as we expected to the announcement of the SourceGas transaction last month. And finally slide 33 illustrates the focus we place every day on operational excellence and on being a great workplace. Our safety record year to-date is outstanding. There is substantial improvement over prior years. We’re working hard to continue that throughout the rest of the year. And then also during the quarter we’re very honored to receive 2015 Secretary of Defense Employer Support Freedom Award. That’s the highest recognition that Pentagon gives to U.S. employers for supporting employees serving in the Guard and Reserves. We were one of 15 recipients out of more than almost 3,000 companies nominated for the award. We’ll have the pleasure of receiving that award next month at the Pentagon and White House. And last slide 34 is our 2015 scorecard. As we’ve done for several years now we put this scorecard together which set forth our objectives for the year. It’s our way of holding ourselves accountable to you, our shareholders and meeting our key objectives during the course of the year. That concludes our prepared remarks. I will be happy to entertain any questions.

Thank you, sir. Ladies and gentlemen, we are ready to open the line for your questions. [Operator Instructions] Our first question comes from Matt Tucker of KeyBanc Capital Markets. Your question please.

Good morning. Congrats on a nice quarter.

Hey, good morning, Matt.

First, I wanted to ask about the cost of service gas program, I mean should we look at increase in the CapEx there as a sign that you’re increasingly confident in getting approval and including your Mancos Shale assets?

We haven’t made a final decision to include the Mancos, but that’s certainly the goal we’re working towards. I think as we continue to complete wells this fall we’re getting increasingly confident in the quality of the play. So I view that as a real positive sign for us. And we really like the program. We’ve had a lot of decisions in all the states and definitely plan to get filed this fall.

Got it. And just to clarify, if you don’t include the Mancos assets in the program, would some of the CapEx shift back to the non-regulated side or do you plan to in the current commodity environment, stick with the numbers that you have laid out today?

Realistically, we wouldn’t shift that capital back to normal E&P programs, Matt. At current price levels they just don’t support the rates of return necessary for simple payouts on drilling wells in most of our plays. When you look at the long term cost of service gas program, you’re looking to beat a little different number rather than the spot price of natural gas. So it’s viable there. If we don’t include the Mancos which we certainly hope to include the Mancos, we’re still looking to acquire some producing properties, gas properties that will be relatively small, but we would include those in the cost of service gas program instead. So the CapEx forecast we have in there is really for the Mancos and/or acquisition of some small producing properties, all of which would be included in a cost of service gas if things work out as expected here.

Okay. Thanks. So I think I understand - you think the regulators would take a longer-term view, so while it may not make sense to invest over the next couple of years in the non-regulated side, they would look at it differently?

Yes. We feel pretty strongly that the best time to implement a cost of service gas program is when gas prices are low. Drilling cost are little lower, obviously not low enough to just drill for rate of return, but when you look at long term life of property hedge on gas prices which essentially cost of service gas program provides, it’s a great time to get a program in place. It gives you a relatively low number on a per Mcfe base, that will be around for years to come. And then you’ve got the program in place when the gas prices do rebound and customers can reap the entire benefit. Makes a lot more sense to implement when prices are low than after prices have already started to rise.

That’s very helpful. Thanks. And then I just shifting gears, wanted to ask about the wind farm application and I guess just give us a sense what’s changed versus in the bid versus the last time. Is it just lower now or what gives you optimism that it will get improved this time? And then as a follow-up to that, if the cost to construct end up coming in above what you’re assuming or the developer is assuming, is the developer on the hook for those costs?

The last part of your question is yes. The first part is really what changes, there are several things, but when we went into the commission last year one of the concerns they expressed with the projects we proposed was that we had evaluated those against the higher forecast for natural gas prices. And so one of the primary suggestions they made really was to go back to the suppliers, see if you can get better bids, but then obviously evaluate those against the more current natural gas price forecast which we have done. We still believe that this project is in the best long term interest of our customers at Colorado Electric and so we’ve re-proposed that. Hopefully the commission will agree with this.

Great. Thanks, Dave. I will jump back in the queue.

Thanks, Matt.

[Operator Instructions] We have a follow-up from Matt Tucker. Your line is open.

Okay, great. I noticed the costs for a couple of the Whittaker flats wells completed earlier this year had gone up little bit relative to the first quarter slides. Could you just comment on what was going on there?

I don’t have that slide sitting in front of me, Matt, but I think the Whittaker flats numbers actually look pretty good. We had a couple wells on Homer Deep 9-11 pad that were just a little bit higher, those wells are deeper for one thing by almost a couple of thousand feet and total measured depth; Whittaker Flats more in the 16,000 range or little more and there some of the Homer Deep wells are 18,000 feet measured in depths so there is a difference in cost related to that. On the 9-11 pad we did have a few drilling problems and you can see that on a graphs basically where we stay at the same place for quite a while don’t make much progress. But overall I think we are very happy with the way the drilling is gone and interestingly the 9-11 pad was the least modern of the three rigs that we were running in the play. And so, what we’ve seen in the Whittaker Flats and on the Homer Deep 7-23 pad is really good drilling efficiencies in cost that you will see that as we move forward into the following quarters and give you a full detailed cost information on those wells, but those are two really purpose built rigs that are designed to drill these deeper horizontal wells efficiently and safely and they did a bang up job for us. So, I think as we get some more numbers out there you will be pleased with what you see. That combined with the fact that just service cost have come down overall anyway due to the downturn in the industry.

Thanks, and I actually misspoke. I meant to refer to the Homer Deep wells, but that commentary was helpful. And the follow-up to that the 7-23 wells that you're not expecting to produce now until late 2016, early 2017, can you test those wells earlier or do you just not complete them until the later date?

No because you need to do the full frac job to do an adequate test and the fracs on those four wells we’re predicting are going to cost around $30 million. And again if we just test them and shut them in, it doesn’t make a whole lot of sense. We don’t need the production out of the plant for at least another full year because of the plant capacity issue. If we were concerned that we really needed those well test results, we would probably be planning on completing them still even though we can’t produce them just to get the well test results, to increase our confidence and the predictability of the program. What we’ve seen so far we’re pretty pleased with the predictability of the program and don’t really anticipate needing the results of those four wells to be fairly confident and the ongoing viability of the drilling program there.

Makes sense, thanks. And then just on the SourceGas acquisition, your equity currency has lost a little value since you announced the deal. Does that impact your accretion expectations or are there other levers you can pull or adjustments you can make to the financing plan to offset that?

Sure, Matt this is Rich. I mean there is a lot of things we are looking at there that the reduced CapEx at E&P in 2016 and 2017 certainly helped in terms of post acquisition how quickly we will delever. So our attempt is going to be to finance this as aggressively as we can in terms of least amount of equity while maintaining our strong investment grade ratings, so we’re looking at all those things we should generate good cash flow in the second half of the year. My hope is that we’re not going to have to issue as much equity is what you see in the deck, but we’ll be looking at all that as we move forward.

Okay, that's all I had. Congrats again on a nice quarter.

All right. Thank you, Matt.

[Operator Instructions] At this time I am showing no further questions. I would like to turn it back to David Emery for closing remarks.

Very well thanks for joining us this morning everyone. We appreciate your time and attention and obviously we appreciate your continued interest in Black Hills. As I said at the beginning of the call we’re really excited. We had a great quarter, the announcement of SourceGas obviously is a huge, another large transformational acquisition for us and we are excited about getting that deal closed in the next year or less hopefully and getting it integrated into our existing utilities. So I look forward to next quarter. Talk to you then, thank you.

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good day.