Jerome E. Nichols - Director of Investor Relations & Corporate Communications David R.

Emery - Chairman, Chief Executive Officer and President Anthony S. Cleberg - Chief Financial Officer, Principal Accounting Officer and Executive Vice President

Kevin Cole - Crédit Suisse AG, Research Division Jeff Gildersleeve Shelby G. Tucker - RBC Capital Markets, LLC, Research Division Matthew Barnett

Thank you, Esteban. Good morning, everyone, and welcome to the Black Hills Corporation 2013 Fourth Quarter and Full Year Earnings Call.

With me today are David Emery, Chairman, President and Chief Executive Officer; and Tony Cleberg, Executive Vice President and Chief Financial Officer. Before I turn over the call, I need to remind you that during the course of this call, 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 statements.

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 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. Good morning, everyone.

On Slide 3 of the webcast presentation, for those of you who are following along, our format will be similar to prior quarters. I'll give an update on the quarter and the year from a highlight perspective.

Tony Cleberg will go through the financials. And then I'll talk about the forward-looking strategic overview.

So skipping to Slide 5, fourth quarter highlights. From a business environment perspective, we had colder weather in the quarter, both compared to last year and even compared to normal.

While the cold weather certainly is good for our utility business, is it does create some challenges in some of our other subsidiaries. For example, it slows down things like drilling and completion in connecting new wells in our oil and gas subsidiary and things like that.

But overall, very positive impact of the weather for the quarter. Highlights on the utilities side.

Black Hills Power here, just a couple of weeks ago, filed a request with the Wyoming Public Service Commission to increase our electric revenue in Wyoming from Wyoming customers primarily related to the Cheyenne Prairie Generating Station. Black Hills Power also plans to file a case later this quarter with the South Dakota PUC.

That case will also be related to the Cheyenne Prairie Generating Station. In early January, Black Hills Power also received an order, an accounting order from the South Dakota PUC, basically allowing restoration costs from a severe October blizzard that we had here in the Black Hills to be classified as a regulatory asset.

That's until we apply for our next general rate case at which we'll propose amortizing those costs. Really, there's only several million dollars worth of incremental O&M there and all of those have been recorded as a regulatory asset.

We also have a few million in incremental capital from the storm. That, obviously, will also just be dealt with in our next general rate case, which as I said before, we're going to be filing here by the end of the quarter.

Cheyenne Light in early December filed a request with the Wyoming PSC, also related primarily to the Cheyenne Prairie Generating Station, but we also filed a small gas case for Cheyenne as well. In Colorado, we received the Colorado PUC's initial written decision related to our Electric Resource Plan there.

That decision approved the settlement agreement for the construction of a 40-megawatt gas-fired turbine at our Pueblo Airport Generating Station. That decision's still appealable, we don't yet have the final written order.

So until we do, it's not completely final. But we would plan on, and have already, at least, commenced air permitting activities and some other things related to that facility.

Moving on to Slide 6, continuation of the highlights. During the quarter, and actually all year, we continued our efforts to acquire small utilities, primarily municipals, near our existing service territories.

And we were successful in doing several of those during the year, adding about 900 customers. And then in January of this year, we announced a small gas LDC acquisition in Northeastern Wyoming, adding another 400 customers.

So not a huge needle mover but great acquisitions, nonetheless, they're very easy to integrate and operate. On the oil and gas side, we completed 2 horizontal Mancos Shale wells on the Piceance Basin.

One of those wells was placed on production in late December, and the second well in late January. If you recall, those 2 wells were part of a transaction, where by drilling and completing them, we earned 20,000 acres of additional lease hold in the Piceance Basin.

And that's been done. Most wells are coming on a little slower than planned because Summit, who was our gas gatherer in the area, has not yet completed their new gas processing plant, and so we're of a little rate restricted there.

But both wells are on and producing. As a reminder, we do have a confidentiality agreement in place related to that transaction, which really restricts our ability to disclose, certainly terms of the transaction itself and the individual details on individual wells, including things like specific production rates and whatnot.

Moving on to the corporate side. Last week, our Board approved a dividend increase for the 44th consecutive year, increasing our quarterly dividend to $0.39 a share, which is an equivalent to an annual rate of $1.56.

That's $0.04 above last year's number on an annual basis. And then last week, Moody's raised our corporate credit rating to Baa1, which is the second upgrade we received from Moody's in the past year.

On November 19, we completed our largest public debt offering. We achieved $525 million or 4.25%, 10-year notes and we used that to retire some higher cost debt, settle some interest rates, swaps and paid down our general corporate borrowings.

Moving on to Slide 7. From a financial perspective for the quarter, we earned $0.70 a share as adjusted, compared to $0.68 per share in the fourth quarter of 2012.

On Slide 8, the full-year financial highlights or EPS as adjusted was $2.45, compared to $2.9 in 2012, which is a 17% growth rate year-over-year. The $2.45 figure exceeds the top end of our previously-issued guidance with the top of which was $2.40, primarily as a result of a pretty cold late fourth quarter, December in particular.

Slide 9 provides a reconciliation of the fourth quarter of '13 earnings from continuing operations as adjusted and reconciled that to the fourth quarter 2013 results. Pretty minor variances between the entities, a little lesser performance in a couple of the businesses and a little stronger on the corporate side, primarily related to some of our financing activity.

On Slide 10, the reconciliation of the full year 2012 to full year 2013, continuing operations as adjusted, improvements in gas utilities, Power Generation, Coal Mining and then, certainly on the corporate side, related to the financing activity and those were partially offset by slight declines in Electric Utilities and Oil and Gas. Now I'll turn it over to Tony Cleberg, our Chief Financial Officer, for the financial update.

Tony?

Thank you, Dave. Good morning.

As Dave described, we're very pleased with our fourth quarter and our full year performance. Compared to 2012, our earnings from continuing ops as adjusted grew 3% for the quarter and 17% for the full year.

You may recall our Q4 earnings in 2012 improved 48% over the fourth quarter of 2011. So we were encouraged by another increase in this quarter.

For the full year, our earnings exceeded our upper end of the range. And, as Dave mentioned, that it was primarily driven by weather, and specifically, more specifically, a very cold December.

Moving to Slide 12, we report GAAP earnings and reconciled earnings as adjusted. A non-GAAP measure.

We do this each quarter to isolate special items and communicate earnings that better indicates our ongoing performance. This slide displays our last 5 quarters and the full year.

During the fourth quarter of 2013, we have 3 special items. The first special item was a reduction of $0.01 for a mark-to-market gain on $250 million worth of de-designated interest rate swaps.

For the full year, the 2013 gain on those same swaps was $0.44, compared to $0.03 in 2012. As we announced in December, we settled these de-designated swaps once we completed the $525 million worth of financing.

The next 2 special items relate to financing activity in the fourth quarter. We calculated the impact of these items as if the financing had been completed on December 31.

So the settlement cost, negative carry and interest savings during the quarter, were netted to calculate the impact of these special items. The first special financing item was an addition of $0.15 for the settlement of swaps on project debt and the write-off of related deferred finance fees in our Power Generation segment.

We paid off this debt prior to maturity to capture an overall interest rate savings. The second special item of $0.13 relates to redeeming $250 million of 9% notes which were due May of 2014.

We paid make-whole premium and wrote off deferred finance fees. The early redemption had a slight projected economic benefit, but more importantly, it positions us to report a clear picture of our recurring earnings in 2014 and thereafter.

So considering these special items, Q4's EPS as adjusted from continuing ops, was $0.70, compared to $0.68 in 2012. Our full-year continuing operations were $2.45, compared to $2.09, an improvement of 17%.

Slide 13 displays our fourth quarter revenue and operating income. Later I'll discuss major differences between the years, but here, the main point is that 88% of our operating income came from our electric and gas utilities in the fourth quarter.

Our operating income as adjusted declined $3 million during the quarter compared to 2012, which resulted from higher expenses, partially offset by margins. The higher expenses were driven by increased employee costs due to cash and stock incentives.

We had a very good year. Moving to the full year, Slide 14.

Revenue increased by $102 million, reflecting higher volumes and higher gas prices in our gas utilities. The better rates were slightly higher megawatts in our Electric Utilities.

This was partially offset by lower production in our Oil and Gas segment. Operating income as adjusted improved 4% compared to 2012 with increases in Power Generation Utilities and Coal Mining.

Oil and Gas declined by $5.6 million, due primarily to the sale of the Williston Basin assets in 2012. Slide 15 displays our income statement for the fourth quarter and the full year.

Some noteworthy changes include increases in our operating expenses in 2013. Three factors accounted for almost all of the increase.

First, 2012 expenses were lower because of an aggressive cost containment initiatives implemented to offset earnings shortfalls in 2012, which were caused by a very mild weather in the first quarter. The second, our variable compensation, which is aligned with shareholder interests, increased substantially in 2013 due to strong performance and stock price appreciation.

The last factor was a general increase of about 2.5%. So we remain diligent in managing our overall cost structure.

On later slides I will discuss operating income in more details. So moving down to interest expense.

You'll note a reduction compared to 2012 of $3.6 million during the quarter and $14.8 million for the full year. The reduced interest expense reflects lower rates and lower average outstanding debt in 2013, compared to 2012.

In the fourth quarter, we completed a number of financing transactions. After we issued $525 million in 10-year 4.25% notes, we called the $250 million of 9% notes which were due May 15, 2014.

We paid off project debt related to nonregulated assets and settled $250 million of de-designated swaps for $64 million. Going forward, these actions should reduce -- should result in a substantial interest savings.

As you may recall, we used the proceeds from our Williston Basin sale to redeem $225 million of 6.5% notes in the fourth quarter of 2012 and paid a make-whole premium. Continuing down the income statement, the effective income tax rate in the fourth quarter compared to the prior year was about the same at 37%.

For the full year, both 2012 and 2013, we had an effective tax rate of 35%. The last noteworthy item was our EBITDA.

During the quarter, we produced $107 million of EBITDA as adjusted, which is about flat compared to 2012. For the full year 2013, our EBITDA declined slightly to $399 million.

Our Oil and Gas segment's EBITDA declined by $22.4 million in 2013, primarily due to selling the Williston Basin assets in 2012. So improvements in other segments offset the Oil and Gas decline.

Discontinued operations relate to the divestiture of our Energy Marketing business in the first quarter of 2012. During the quarter, we recorded a charge for a final purchase price adjustment.

Moving to Slide 16. We display our Electric Utilities segment revenue and operating income.

The Electric Utilities revenue increased in the fourth quarter by $10 million from 2012. And this is driven by weather and rate increases, including riders.

Megawatt usage increased 4% in Q4 compared to 2012. Our operating income as adjusted declined by $4.8 million during the quarter compared to 2012.

The decline reflects higher expenses and 2012 included the receipt of $2.1 million of a construction bonus. The higher expenses were primarily for employee cost, vegetation management and property taxes.

For the full year, revenue increased about $38 million, primarily due to pass through, purchased power cost and rate cases. Operating income was flat with increased margins offset by increased expenses.

Moving to Slide 17. Gas utilities revenue increased $26 million in the fourth quarter, driven by 15% higher heating degree days and a 7% higher gas price.

The operating income improved $2.5 million or by 10% in the fourth quarter compared to 2012. Q4 retail and commercial dekatherms sold increased about 19% year-over-year.

And the Q4 O&M expenses were slightly higher, primarily for employee costs compared to 2012. For the full year, the colder weather was primarily the driver of the $9.6 million improvement in operating income.

As you may recall, 2012 had an extremely mild winter in our gas states. For our gas utilities, the heating degree days in 2013 were 9% higher than the normal 30-year average, while 2012 were 13% lower than the 30-year average.

So if you think about the weather impact for the combined electric and gas utilities, it was a strong positive for both the quarter and the full year. The next segment, Power Generation, operating income had a slight decrease in Q4 primarily due to scheduled maintenance outages.

For the full year, operating income improved $2.2 million due to higher off system sales margins. This segment performed slightly better than expected.

Moving to Coal Mining on Slide 19. We saw operating income in Q4 declined by $600,000 from 2012.

This was primarily driven by a power plant outage at our major customer. With the continued progress in reducing our mining costs and executing our revised mine plan which lowered our stripping ratio in Q4 to 0.5 compared to 1.5 in 2012.

For the full year, the operating income improved by $3.2 million compared to 2012. We have a price reopener with our major customer and we should see better margins starting in Q3 of 2014 in this segment.

Slide 20 is our Oil and Gas. In here, we had a transitioning year after selling our largest oil producing properties in the Williston Basin.

Overall, fourth quarter production increased 11.5% from 2012, driven by an 8.5% increase in natural gas and a 20% increase in oil. From a pricing received standpoint, the oil decreased by 13%, and the natural gas price decreased by 20% in the quarter.

From a cost perspective, our O&M expenses decreased by $500,000 compared to 2012. So we continue to see good cost management.

Depletion increased in Q4 by $1.3 million compared to 2012. And this was really driven by higher production and higher depletion rate, due to the impact of having oil wells.

Sequentially, our Q3 production declined -- or sequentially from Q3, our production declined by 2%, due primarily just because of normal declines in our gas wells, partially offset by a 6.5% increase in our oil production. With the recently completed Mancos wells, we expect production to increase in Q1 compared to the fourth quarter.

For the full year, production declined by 24% driven by the sale of the Williston Basin assets. Prices received for oil increased by 7%, and natural gas declined by 19%.

The depletion rate for 2013 was $1.83 per Mcfe compared to $2.87 in 2012. Slide 21 provides an estimated rate base at year end.

For 2013, we were flat with 2012 at $1.7 billion. The capital additions, excluding Cheyenne Prairie, were offset by increases in depreciation and deferred income taxes.

We expect Cheyenne Prairie Generation Station to be included in rate base October 1, 2014. Moving to our capital structure on Slide 22.

This shows our current capitalization. At year-end, our net debt to capitalization ratio was 52.9%, an increase from 2012, yet low enough to fund our capital program.

With the $525 million 10-year note issuance in November, we now have over 90% of our long-term -- 90% of our debt as long-term. As Dave mentioned, we were upgraded last week by Moody's to Baa1, which was the second upgrade in less than a year.

Just as a reminder, in 2013, we were upgraded to BBB flat with S&P and Fitch. And Fitch also has us on positive outlook.

In the press release, we reaffirmed our 2014 earnings guidance in the range of $2.50 to $2.70. This is for EPS as adjusted and excludes special items.

There is a slide in the appendix that lists the primary assumptions regarding our 2014 earnings guidance that we made in November. Overall, we expect improvement in the operating income over 2013 and a notable reduction in our interest expense which contributes to the improved EPS for 2014.

On Slide 24, to conclude, we've achieved strong performance for both the fourth quarter and the full year. And we're really proud of our improving financial performance over the last 5 years.

And we really look forward to the continuing growth in our utilities and capturing the value of the Mancos Shale properties. And with those comments, I'll turn it back to Dave.

Thank you, Tony. Moving on to Slide 26, out strategic objectives.

Consistent with our prior quarters, we have 5 major strategic objectives, all of which are focused primarily on being an industry leader in everything we do. We want to be a leader in operational performance, earnings growth, earnings upside opportunities and certainly, our track record of 44 consecutive annual dividend increases.

We also plan to maintain our minimum BBB equivalent unsecured credit rating. As you may recall, that was an objective to achieve a BBB credit rating and that's a goal we met this calendar year or last calendar year 2013.

Slide 27 exhibits exceptional performance relative to our peers in safety, reliability and several other utility efficiency measures. On Slide 28, you can see our superior plant availability and starting reliability.

Slide also demonstrates that we have a very modern generation fleet. It's very new.

And then our power plant construction safety record is great. Related to the power plant availability and starting reliability, I mean, those are keys from a customer perspective and that we're able to better utilize our generation assets which saves customers money in the long-term.

Slide 29 illustrates our generation by fuel type and further demonstrates the ongoing modernization of our fleet as we continue to add new resources and have now retired, or in the process of retiring, a couple of our older both gas-fired and coal-fired plants. Slide 30 related to earnings growth.

Tony talked about our 5-year trend. We expect continued strong earnings growth, driven primarily by capital spending to meet customer needs in our utilities and also to grow our nonregulated energy businesses.

Capital spending is projected to be far in excess of depreciation. Slide 31 provides a little more detail on historical and projected capital spending and it's broken out there by business segment and for our electric utility, we actually break it out a little bit further for generation transmission and other.

Slide 32 is a subset of Slide 31 providing a little more detail for select major utility projects, some of which even extend beyond the 2016 year which is the final year that we disclosed specific capital totals for the corporation. On Slide 33, helping drive earnings growth, strong earnings growth in the next couple of years is our Cheyenne Prairie Generating Station.

As Tony said, it's a $222 million, 132-megawatt plant and it's jointly owned by 2 of our subsidiaries, Black Hills Power and Cheyenne Light. That project is on-time and on budget to be in service by October of this year.

Most of the contracts have been awarded. So we're pretty firm on our cost target there and feel real good about where we're at, making excellent progress.

And also with a very, very good safety record, we've only had 1 safety incident to date on the site. Slides 34 through 36 provide a regulatory update summary for our utilities.

Most of these I covered in the highlights so I won't repeat them here. But on Slide 34, it does talk a little bit more about our plans at Black Hills Power to file our rate case in South Dakota, related primarily to that Cheyenne Prairie Generating Station and with the intent of those rates being effective with the plant in service date in October.

And on Slide 35, near the top, we talked about this last year, but we're continuing to evaluate the timing for Cheyenne Light to exercise its option to acquire the Wygen I coal-fired power plant. As we've stated previously, we intend to exercise that option when the impact will be neutral to Cheyenne's customers.

We're continuing to evaluate the timing of that. This quarter, we've at least included some numbers that can help you come to purchase price and current book value of the facility.

Skipping to Slide 37, from a value upside perspective, we remain very focused on our Oil and Gas assets. We plan to prove up and capture the substantial value of our existing Oil and Gas properties and also continue to pursue disciplined oil exploration projects, primarily in place with impactful reserve potential.

For 2014, our drilling program, we intend to drill and complete up to 6 horizontal wells in the Mancos Shale and the Piceance Basin, and then continue our selective oil-well exploration program as well. Moving on to Slide 38.

As we've said previously, our Oil and Gas leases, existing leases, in the San Juan and Piceance Basins, have net resource potential to our interest in excess of 2 trillion cubic feet of natural gas. It's noteworthy that we have not updated the tables on these slides to include results of the wells that we've drilled in 2013, due primarily to the confidentiality agreement that I mentioned earlier.

We also have not included that additional 20,000 acres in this table as far as potential as well. We have earned the 20,000 acres and they are part of our total.

We just haven't updated these numbers to include those, again, based on the confidentiality agreement we have in place. On Slide 39, also as noted earlier, during the year, we met our goal of achieving a BBB equivalent or better credit rating from all 3 credit agencies.

A very substantial step, as Tony said, based on the improvement in our financial condition over the last several years, we're pleased that all 3 rating agencies recognized our performance on the financial side. And Slide 40, as I already noted, we're very proud of our dividend track record, increasing our dividend to annual dividend to shareholders for 44 consecutive years.

One of the longest streaks in the utility industry and one we're quite proud of. On Slide 41, this is our 2013 scorecard, and as you know, this is something we've been doing for several years.

At the beginning of the year, we set out our goals and objectives for the year, key strategic goals and objectives, and then show you the progress that we've made throughout the year. Slide 41 illustrates the great progress we made in 2013 towards our key objectives, essentially accomplishing all of what we set out to do for the year.

And then finally, Slide 42 is the goals and objectives for 2014. Which sets forth our plans for the year and you'll be able to monitor our progress quarter-to-quarter as we go through the year.

That concludes our prepared remarks. We would be happy to open up the lines for questions, if anyone has any.

I'm just trying to reconcile the rate base slide, the Slide 21. It looks like in 2013, your rate base fell.

And if I just compare that versus your Slide 30, where you have the CapEx versus depreciation, your rate base should have increased. Is this rate base number just the summation of all prior approved rate basis and not necessarily the hypothetical rate base that should be today?

What we're trying to estimate, Kevin, is what our rate base is as of the end of 2013. On that slide, it certainly doesn't include all the capital expenditures on Cheyenne Prairie and some of the things that still have to go into rate base from that standpoint.

But we did -- we do have some movement on the deferred taxes. As you know, with all utilities, we really enjoyed large deferred taxes on the -- because of the bonus depreciation.

And so we're getting some movement in that which partially offset some of the increase for the capital expenditures.

Okay and so should we expect rate base to fall into '14? Or once you get Cheyenne Prairie service it should -- then you'll get the full true up for Cheyenne Prairie?

Right, that's right. So as always, things get a bit lumpy with a construction.

And then I guess with EMP, so on the Summit project. What was the cause of the delay and when is it expected to be up and going at full capacity?

Yes, they were originally planning on being on late last year and weather and construction delays and other things related to their plant construction have delayed that. That facility is still not yet producing.

We hope that it will be producing here literally any day, but it's restricting the wells' output on the 2 new wells we've put on because we don't have a takeaway capacity without the plan. So we're producing the wells, we're cleaning them up after the frac and completion but we're certainly not producing them at anywhere near full rate right now because the plant did not yet completed.

Does the Summit project should be completed by the time to get your 6 other wells done this year?

Well I certainly hope it doesn't take that long. We won't start drilling until spring and it certainly should be done -- really should be done now, hopefully will be done at least this month, if not sooner.

Okay. And then on the additional 20,000 acres that you earned, is there a requirement for you to have an active drilling program of that acreage to keep it?

There's some minimal requirements, Kevin, but nothing major.

Okay. And then I guess our last question on Slide 38.

Is the 6 to 8 Bcf per well assumption still the right number?

Well, based on a 4,000- to 5,000-foot lateral, it is. We drilled these more recent wells with longer laterals.

And as I said, we can't disclose individual well results. So we can't provide an update really to that slide until we can publicly disclose the results of those reserves.

But with longer laterals you would typically expect higher reserve numbers per well.

Just can you remind me then when the confidentiality agreement ends or when your 6 wells, that you're going to drill outside of the confidentiality agreement, will come online?

Well, the confidentiality agreement, I'm not 100% sure of this, Kevin, but I believe it's at least 6 months from the date of first production on those wells. So you're looking at midyear at a minimum for the CA and it could be longer.

And then the other wells, basically, our intent would be to start drilling those in the spring. We've got -- some of the areas, we've got wildlife restrictions and other things that preclude us from commencing drilling until April, May, maybe even a little later than that.

And somewhat weather depended if they have a really wet spring, we'll probably wait until the mud goes away before we move in. And then it takes a month plus, 1.5 months per well to drill and then several more weeks to complete.

And we would just plan on doing it pretty continuous activity. But we will be drilling several wells from a single pad.

So when you do that, you drill for a few months and then you move your drilling rig and you complete all the wells at the same time. So you don't see production coming on one well at a time, which will delay production, probably until at least mid to late third quarter, before you're seeing any new production, possibly later than that.

Okay, that's helpful. And then, sorry, one last question.

Are you giving your role for the CapEx plan? Do you still expect to be equity free through this 2016 planning period?

Yes.

We made a statement to that affect in the 10-K that will come out here soon.

It's Jeff Gildersleeve. I just wanted to look at Slide 59, your guidance assumptions for the commodity, you have of NYMEX gas at $3.70 and wellhead of $2.37.

We've seen a lot of volatility, so I just wanted to take your perspective on those assumptions.

Yes, I mean, as Tony said, those are the assumptions we had when we put out our guidance in November 5. And we don't update those typically during the year, unless there's some major change.

Things are always moving one way or the other. And we talked a little bit about, for example, some of plants being a little slower.

I mean, some of those, we don't typically update our guidance for price movements unless we see -- we've got actual earnings in related to that price increase than we do. But we hedge a fair amount of our gas and oil.

And so there's not a lot of incremental production except new production that comes on that is unhedged, typically. So we end up hedging 2/3 kind of number of our total production.

Okay. Yes, because I mean, I think the 14 strip's like 4.60, and then when you look at the -- your hubs, your gas hubs out there, can you just remind us what hubs in the Piceance and San Juan that you're going into?

Well, in the San Juan, we're typically at San Juan. And then depending on where the gas is in the Northern Rockies, Northwest Rockies, typically.

Okay. Yes, because there's been a lot of spot volatility, as you said, you're hedged a lot and the excess gas hasn't come on.

But there's some pretty extreme prices out there now. So you said you're 2/3 hedged on your production?

Roughly or more.

And we disclose our specific hedges in doing the K, Jeff, so it's very easy to figure out the total hedged volumes when you see the K.

Okay. But you wouldn't typically update your assumptions if they changed throughout the year?

No, not unless. If we were to raise guidance driven by say, just pure price increase or something, we might change that assumption.

But typically, we leave our assumptions the same unless there's something that leads us to raise our guidance and then we typically would revise at least a few of the assumptions there.

In your conversations with the commissioners, do you have any updates on the idea of rate basing natural gas reserves somewhat what you see in Utah?

No. That's something that we know others are doing and certainly it's something that we've at least contemplated.

But haven't really had any substance of discussions certainly with commissions related to that. It's something that's certainly intriguing to us with the natural gas holdings we have, but we really haven't gone a whole lot further than that at this point, Shelby.

Could you just remind us on the size of the gas processing plant with Summit and whether or not that size is meant to satisfy the 2 wells being drilled or the entire drilling program?

Well, it's not going to satisfy the entire drilling program. It'll certainly help -- the way that plants designed is it's designed to be brought on in 20 million cubic feet a day increments.

And so they'll build it basically 20 million cubic feet of capacity at the time based upon our request. And then the first phase is going to be 20 million a day and that's the phase we're waiting for.

All right. Thank you.

Well, thank you, everyone, for joining us this morning. We very much appreciate your time and your continued interest in Black Hills.

We're very excited about our performance in 2013 and expect good continued growth going in 2014 as well. So thank you, have a great day and a good weekend.