EQT Corporation (EQT) Q1 2013 Earnings Report, Transcript and Summary

Hello, and welcome to the EQT Corporation First Quarter Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Mr. Patrick Kane, Chief Investor Relations officer. Please go ahead.

Thanks, Amy. Good morning, everyone, and thank you for participating in EQT Corporation's First Quarter 2013 Earnings Conference Call. Today with me are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream, Distribution and Commercial; and Steve Schlotterbeck, Senior Vice President and President of Exploration and Production. This call will be replayed for a 7-day period beginning at approximately 1:30 p.m. this afternoon. The telephone number for the replay is (412) 317-0088. The confirmation code is 10025391. The call will also be replayed for 7 days on our website. To remind you, EQT Midstream Partners, ticker EQM's results are consolidated in EQT's results. There was a separate press release issued by EQM this morning, and there's a separate conference call today at 11:30, which creates a hard stop for this call at 11:25. If you're interested in the EQM call, the dial-in number is (412) 317-6789. The confirmation code is 10025400. In just a moment, Phil will summarize EQT's operational and financial results then Dave will provide an update on our strategic and operational matters. Following Dave's remarks, Dave, Phil, Randy and Steve will all be available to answer your questions. I would like to remind you that today's call may contain forward-looking statements related to the future events and expectations. You can find factors that could cause the company's actual results to differ materially from these forward-looking statements listed in today's press release and under Risk Factors in EQT's Form 10-K for the year ended December 31, 2012, filed with the SEC as updated by any subsequent Form 10-Qs, which were also filed with the SEC. Today's call may contain certain non-GAAP financial measures. Please refer to this morning's press release for our important disclosures regarding such measures including reconciliations to the most comparable GAAP financial measure. With that, I would like to turn it over to Phil Conti.

Thanks, Pat, and good morning, everyone. As you read in the press release this morning, EQT announced first quarter 2013 earnings of $0.66 per diluted share, a 38% increase from EPS in the first quarter of 2012. Operating cash flow also increased by 34% to $304 million for the quarter. We had a very solid operational quarter including record produced natural gas sales as well as record gathering volumes at Midstream. The high level story for first quarter at EQT was strong volume growth coupled with lower unit cash cost in both the production and the Midstream businesses, which was partially offset by lower realized commodity prices. Even though NYMEX was 22% higher than the previous year, we realized a lower effective natural gas price after accounting for the effect of our hedges as the number of higher-priced swaps and collars rolled off at the end of 2012. Also, NGL prices were 23% lower versus the same quarter last year. Earnings at our distribution segment were higher than last year as a result of weather that was back to normal as compared to the record warm winter that we had last year. As a reminder, EQT Midstream Partner results are consolidated within EQT Corporation's results, and EQT recorded $9 million of net income attributable to noncontrolling interests or $0.06 per diluted share in the first quarter. Moving on to the segments, starting with EQT Production operating results. The story in the quarter at EQT Production continues to be the growth in sales of produced natural gas. The growth rate, as you saw, was 47% in the recently completed quarter over the fourth -- first quarter of 2012. That growth rate was all organic and the growth was driven by sales from our Marcellus Shale play, which saw volume growth of 103% year-over-year. NGL volumes were also higher, 52%, versus last year. As I already mentioned, the average realized gas price was lower in the quarter. The realized price at EQT Production was $3.14 per MCFE compared to $3.59 per MCFE last year. At the corporate level, EQT received $4.27 per MCFE or 12% less than last year. Produced liquids, excluding ethane, accounted for 6% of the volume and 23% of the unhedged revenues in the quarter. Total operating expenses at Production were $40 million or 29% higher, quarter-over-quarter. Higher DD&A expense accounted for $38 million of the $40 million increase and was driven by the volume growth, as the average completion rate was essentially unchanged. Production taxes were $4.2 million lower, but I remind you that last year, in the first quarter, we recorded a $6.2 million charge related to PA Impact Fees that was related to periods prior to 2012. Excluding that, EQT actually experienced an increase of $2 million in Production taxes consistent with the higher volumes. Other operating expenses at Production were $6 million or 18% higher. Since sales are growing at a significantly faster pace than expenses, per unit cost continue to obviously improve. Per unit LOE, excluding production taxes, was 20% lower at $0.16 per MCFE and per unit SG&A was 26% lower at $0.29 per MCFE. Moving onto the Midstream business. Operating income here was up 32%. This is consistent with the growth of gathered volumes and increased capacity-based transmission charges and increases in interruptible transmission volumes and revenue. Gathering net operating revenues increased by $12.6 million as gathering volumes increased by 42% in the quarter while the average gathering rate declined by 16%. The decline in rate continues to be driven by the increasing Marcellus mix. The Huron gathering fee remained unchanged at a $1.35 per MCF, while the average Marcellus gathering fee declined by 9% to $0.60 per MCF. Transmission net revenues increased by $14.4 million while storage marketing and other net operating revenues was down $5.2 million in the first quarter. Margins at storage continue to deteriorate year-over-year due to the lack of winter-summer spread in the gas prices and low day-to-day volatility in gas prices. Given current market conditions, we still estimate the full year 2013 net revenues in storage marketing and other will be approximately $30 million. Net operating expenses at Midstream were $3.7 million higher quarter-over-quarter, mainly from higher depreciation expense consistent with our capital investments and growth. On a per unit basis, gathering and compression expense was down 32% to $0.19 per MCFE as a result of higher throughput while maintaining our cost structure. Based on the higher estimated volumes, we are increasing our 2013 EBITDA estimate at Midstream to between $350 million and $355 million. Moving on to Distribution, operating income at Distribution was 29% higher after excluding $5 million of revenue applicable to prior periods recorded in the first quarter as a result of the completion of a routine purchased gas cost audit. Adjusted for that, the remaining increase in operating income is explained by weather, as I mentioned. First quarter 2013, weather was in line with the 30-year average but much colder than last year, which according to NOAA was the warmest first quarter on record in the service territory as measured by heating degree days. As a result, adjusted net operating revenue for the first quarter at Distribution in '13 was 16% higher, while operating expenses were essentially flat. Final note on 2013 cash flow as a result of the higher forecasted natural gas prices for our unhedged volumes, we are increasing our operating cash flow estimate for 2013 to be approximately $1.1 billion based on the current strip. We did take advantage of the recent run up in natural gas prices to add to our hedge position for 2013 and 2014. We're approximately 60% hedged for the remainder of '13 and around 30% hedged for 2014. We exited the quarter with $160 million in cash on hand, no short-term debt and full availability under our $1.5 billion credit facility. So we remain in great liquidity position for 2013 and beyond. And with that, I'll turn the call over to Dave Porges.

Thank you, Phil. As Phil summarized, operationally, we are coming off another record quarter with record volumes at Production and Midstream. Before discussing business operations, I will update you on several housekeeping items. First, we have a status update on the regulatory reviews related to the sale of our gas utility, Equitable Gas Company. April 22 marked the expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. The Federal Trade Commission has completed its assessment of the proposed transaction and we are free to proceed from an HSR perspective. We've also submitted filings with the Pennsylvania Public Utility Commission, West Virginia Public Service Commission and the Federal Energy Regulatory Commission, and we'll soon file with the Kentucky Public Service Commission. Each of which must approve the transaction as part of the regulatory process. We continue to expect to receive all necessary approvals by year-end. Second, MLP drops. We intend to execute a significant drop in the third quarter as planned. We expect that EQT Midstream Partners funding of the acquisition will include the issuance of additional equity units. As we have discussed before, the MLP becomes eligible to file a shelf registration statement with the SEC in early July, and we expect that it will file such a shelf registration at that time, in order to start the SEC registration process. The registration statement, once declared effective by the SEC, will allow for the issuance of equity and debt. If the SEC review is uneventful, we expect to be able to complete the drop in the third quarter as previously discussed. Now on previous calls, we have discussed the possibility of doing a very small drop in the first half of 2013. As we prepared for the so-called test drop, we realized that the time commitment and fixed cost related to a small drop are quite similar to those related to a larger drop. Therefore, we decided not to proceed with the small drop but rather focus our efforts on a successful large drop in the second half of the year. In anticipation of your questions related to specific timing and size of the third quarter drop, please keep in mind that SEC rules limit what we're allowed to discuss in advance of security offerings and intend to comply with those restrictions. What I can say, which we have said in the past, is that we intend to fund our Midstream CapEx investments and proceeds from drops to -- with proceeds from the drops to EQT Midstream Partners. My third housekeeping item is that we finished frac-ing our first Utica well as planned. And it is shut-in waiting for gathering line, which is on schedule for midyear. We completed drilling our second Utica well and we'll be frac-ing it soon. And we will spot a third Utica well this month. Finally, as has been our normal, we're providing Production sales guidance for the current quarter. Based on our current pad completion schedule, we expect second quarter Production sales to be approximately 85 Bcfe. Now I want to return to our operations. As I said, the first quarter was another very good quarter for EQT. Production exceeded its business plan on both revenues and expenses, driven by volumes that exceeded guidance by 4%. The increased volumes flowed through our Midstream gathering and transmission systems driving the growth in those businesses. And Equitable Gas Company demonstrated its ability to earn a solid return when Mother Nature cooperates. We had our first normal winter in sometime, void by a persistently colder and normal March, and I add that note for the benefit of those of you who did not have the pleasure of experiencing it firsthand. And the results reflect the commitment our team has to providing safe and reliable service to our utility customers. Production volumes were higher than expected -- higher than expectations from turning pads and lines faster than planned from wells performing better than expected. We have discussed the lumpiness of Production growth resulting from the specific timing of turning pads and lines, and I will not bore you with the results from every pad, but I do wish to share some examples. In Greene County, we turned in line an 8-well pad with an average length of 5,800 feet starting at the end of October. The 30-day IP of the pad was 116 million cubic feet or 14.5 million cubic feet per well per day. While too early to estimate precisely, this corresponds to an EUR of 15 Bcfe per well or 2.6 Bcfe per thousand feet of padding. Other Greene County pad was turned in line in December. This pad had 4 wells on an average length of 7,300 feet. The 30-day IP was 94.1 million cubic feet per day or 23.5 million cubic feet per well per day. This corresponds to an EUR of 14.3 Bcfe per well or just under 2 Bcfe per thousand feet of padding. To help you with the math, that's 6.25 Bcf total production from the first month of production from just those 2 pads. Shifting to West Virginia, recently, we have been getting a lot more questions from investors about our position in this state. As many of you know, we have been bullish on West Virginia for some time. Our drilling activity there, which represents 55% of our 2013 Marcellus drilling, is focused in our liquids-rich acreage in Doddridge, Ritchie and Wetzel counties, where we have approximately 80,000 acres. We have begun implementing reduced cluster spacing in Doddridge and Ritchie with tremendous initial success. In Doddridge, we have 8 wells frac-ed with reduced cluster spacing and online for more than 30 days. These wells are significantly shorter than we prefer due to some land issues as they average 2,900 feet in lateral pay, but the results are still impressive. The average 30-day IP was 8 million cubic feet per well per day, which corresponds to an EUR of 5.7 Bcfe per well or just under 2 Bcfe per 1,000 feet of pay. As a footnote, all of the EUR estimates I am quoting for wet gas using industry norm of converting extracted liquids to MCFE at a ratio of 6 MCFE per barrel. The quoted EURs in the wet areas would be higher still if we assumed all ethane in the gas stream were extracted and, therefore, converted at that ratio. In Ritchie, we only have 5 wells online with an average length of 5,640 feet, 2 were frac-ed using 30-foot spacing and 3 with 60-foot spacing. The average 30-day IP was 9.2 million cubic feet per well per day, which corresponds to an EUR of 11 Bcfe per well or just under 2 Bcfe per 1,000 feet of pay. In Wetzel, we also only have 5 wells online, all frac-ed with 60-foot spacing. The average length per well is 3,680 feet. The average 30-day IP in Wetzel was 7.4 million cubic feet per well per day, which corresponds to an EUR of 7.3 Bcfe per well or 2 Bcfe per 1,000 feet of pay. We are testing 30-foot cluster completions in Wetzel this year. As you can see, when we normalize for lateral length, which is how we evaluate well productivity internally, these 17 West Virginia wells, with EURs per 1,000 feet of just under 2 Bcfe, are more productive than our Tier 1 average, which is 1.7 Bcfe per 1,000 feet. And the economics are enhanced by the liquids content and by the higher energy content of the residual gas stream. As you read in this morning's press release or as you've read in this morning's press release, we increased our 2013 Production sales volume guidance to be 33% higher than last year, and we initiated 2014 guidance at nearly 30% growth over the midpoint of the higher 2013 target. To remind you, 2013 Production is primarily determined by our 2012 drilling program and, similarly, 2014 is largely determined by our 2013 program. That is why we are confident giving our preliminary 2014 guidance. As we look at our extensive Marcellus inventory in both Pennsylvania and West Virginia, we are confident that our assets can support growth of more than 20% for several years. Furthermore, with proceeds from the sale of the utility and a continued source of capital through drops of Midstream assets to EQM, we are in strong financial shape and have visibility on sourcing the needed capital. In summary, EQT is committed to increasing the value of our vast resource by accelerating the monetization of our reserves and other opportunities. We continue to be focused on earning the highest possible returns from our investments, and we are doing what we can to increase the value of your shares. We look forward to continuing to execute on our commitment to our shareholders, and we appreciate your continued support. And with that, I'll turn the call over back to Pat.

Thank you, Dave. Amy, let's open the call for questions.

[Operator Instructions] Our first question comes from Neal Dingmann from SunTrust.

Steve or Dave, I'm just wondering, first, just turning to the bit of the Utica that you have, you mentioned about going after and drilling the third well. Wondering, given the acreage that you have as far as kind of lateral length design, what, ultimately, you want to do and if you continue to rest those wells, kind of like a lot of the peers, 60 days or so?

Yes, Neal, this is Steve. Regarding the resting, I think we're kind of open-minded about that. I think we're going to test it and see, and sort of by necessity on these first wells since we're waiting on the gathering system, they will be rested. So we may...

Well rested.

Well rested, yes. So we expect to start flowing those wells midyear. Regarding lateral length, I think we're still believers that in all these shale plays, longer is better. So we drill as long as we can, given the acreage position we have. I think on this first group of wells, I don't have a specific number, but on average, the lateral lengths are fairly long, north of 5,000 feet per well. So we're pretty happy about that.

And I know you've probably said you liked to maybe go after more data, just wondering if you could comment, Steve, about how that's going? And, again, I know you previously said that you would rather do it in the liquid side. Would you entertain looking at some of the Utica more on the eastern dry gas side or just stay more in the fairway?

Well, I think it's all interesting to us, and we monitor results from our competitors who have more data than we have at this point. But I think we're pretty confident in our drilling and completion capabilities. So if good results are coming out of the gasier side of the play, that would certainly be of interest. I think we view similarly to how we view the Marcellus drier gas areas. But for now, our current acreage is in the wetter part of the Utica, and we're going to wait for results like everybody else and see what we have.

Neal, you had mentioned the liquids. And actually, just to clarify, we tended to be more interested in wet gas at the areas that kind of get into the, if you will, condensate window. We haven't really been all that interested in the so-called black oil part of the play, at least not to date.

Great clarification. Thanks, Dave. And then just last question. You guys continue to have just great results, continue to expand, particularly, in the Marcellus, but wondering, Steve, if you could comment about the design on the Upper Devonian, seems like even those results sort of continue to expand. So I guess, number 1, basically using the same technique, complacent -- drilling and complacent techniques there as you do in the Marcellus. And 2, if so, what are we talking as far as drilling locations? It sounds like that could really pick up materially given all your -- even the Devonian potential on top of the Marcellus?

Neal, I think, first, I want to remind you that it's very early in our experimentation of that, so we only have a handful of wells. But it is something we're pretty excited about. And you can see, we're continuing to drill probably even a little bit ahead of where we thought we'd be in terms of numbers of Upper Devonian wells at this point in the year. When we look at that, we think we have, at the current time, with limited information, about 170,000 acres that are perspective. We are using similar techniques, not always exactly the same techniques. It depends on the geology and the mineralogy of the reservoir. And I think we will have to experiment to see what the appropriate lateral spacing and stage spacing is in the Upper Devonian. So there's still a lot of variables that are unknown to us in terms of quantifying the total resource potential. But I think our best guess right now is 170,000 acres, we think, will be economic. And that's -- we'll start off with 1,000 foot spacing and see if it makes sense to go closer than that.

Our next question comes from Stephen Richardson at Deutsche Bank.

Quick question. Just appreciate all the color, particularly around West Virginia and the Greene County results. In context of your comments, David, can you help us a little bit on the -- I noticed your latest investor presentation, Slide 34, which looks like it was just reposted, you still have the same tiering and type curves that's been there for some time, if I'm not mistaken. Can you talk a little bit about not only in terms of where in the tiering we could see some upside, but also where in that tiering too we should be thinking about reduced cluster impact in terms of on impacts on EURs. So I guess 2 kinds of drivers there and, again, where would the upside be?

We're always relooking at those. I recognize that it's not -- perhaps they're not completely keeping up with current results. Some of what we discussed of course had to do with new results in from West Virginia, in particular, but also in how we wind up characterizing the liquids. And we're trying to provide information on EUR that is more consistent, say, with what other folks have done. So I think it's kind of a watch-this-space type of thing. We will continue to look at what those type curves are to make sure that they are reflecting the -- our current thought process. But I'd say, probably, the biggest issue that we've got is making sure that we bring our way of characterizing the liquids a little bit more in into line with folks in the industry have done. And that's the reason that we have quoted the EURs and the EURs per foot the way we did.

Just as a follow-up I guess, is 122-acre spacing the right way to be thinking about Greene County?

We don't really like to talk about acres per well. It's driven so much by lateral length and lateral spacing. So I think right now, in Greene County, it's looking like, in the bulk of Greene County 500-foot lateral spacing, and we try and drill as long as we can. But the spacing per well for a 10,000-foot well is twice the acreage than it is for a 5,000-foot well. So it's not a term we use internally very much, but I think I would maybe use our average spacing of around -- or length of 5,000 feet with 500-foot lateral spacing as a reasonable approximation of our per well drainage.

Great. Thanks for the clarification. One more, if I could, was, could you give us, just a little bit, perhaps on 2014, what we should expect directionally in terms of CapEx to go with that production number at this point. I know it's a little early, but is that the right assumption?

I'd rather not give guidance on that, only because the board is the, obviously, the group that approves that. Our real point in providing the 2014 guidance now was that 2014 production isn't really that dependent upon 2014 capital. It's a pretty small amount of capital relative to, say, what the total that we're spending this year that would be required to hit that kind of guidance. But as we mentioned with these multi-well pads with long laterals, there is a relatively long lead time. So you really do have to look, we think, at least, the way we conduct the operation, you have to look at 2013 capital and results to kind of get a sense of what 2014 volumes are going to be like. The 2014 capital is going to have much more impact on the 2015 volumes. But certainly we do have the liquidity to -- I mean, we have the liquidity certainly to continue spending at the pace that we've been spending.

Next question comes from Phillip Jungwirth at BMO Capital Markets.

You mentioned that you drilled 6 Upper Devonian wells in the quarter. I don't think you talked about any results. Are any of those wells on sale, then could you talk about the results that you've seen from those?

I think we've turned in line a couple of those, but we're -- it's too early to talk about the results.

And then in the Utica, you talked about targeting at least 50,000 net acres. With gas prices having moved up and also chatter about some pretty strong results out of the dry gas window, is that something that you would consider targeting in your leasing efforts or you're still focused in the wet gas part of the play?

Yes. I mean, I think our -- we do have an interest in consolidating the position that we have. And the dry gas area would be a separate area that, again, we monitor the results and, at some point, we may find that attractive, but for now we're focused on our core Marcellus position and building a position in the area where we have Utica acreage that give us enough scale to be efficient.

And of course, as you know, we do have a fair amount of dry Utica acreage that's under our Marcellus acreage. The issue isn't just that it's dry though. It's that as we move further to the east, it's deeper. So it increases the costs. So it's not just the fact that the gas is dry that causes some concern. It's that it's deeper. And certainly I'll mention that the front part of the curve has moved up a lot. The back hasn't really moved up that much. So we've got a pretty flat curve, which is good for cash flows and good for economics, because it brings cash flows forward, but it doesn't materially impact how you view longer-term prospects.

Got it, makes sense. And then on the RCS in West Virginia, you previously talked about 1/3 of the acreage -- 1/3 of your Marcellus acreage can be developed using RCS. Were you concluding the West Virginia wells in that 1/3 or is that incremental?

I don't recall what exactly what went into the 1/3, but I can tell you that we are now doing reduced cluster spacing in the bulk of the areas we're drilling in West Virginia, and really -- so Doddridge and Richie. And in Wetzel, we are currently experimenting with it. But I would say I have high confidence that 30-foot clusters is going to prove to be the preferred method in Wetzel County. So I think in the areas we're currently drilling in West Virginia, the percentage of RCS completions will be very high.

And last question on EQM, I think you'd previously talked about targeting a coverage ratio of 1.1x. In the first quarter, it was closer to 1.9. Is 1.1 still the longer-term target we should expect there?

That certainly was the target we talked about when we marketed the deal. It's going to vary quarter to quarter. We tend to look at it as we think about distributions going forward a year or so. I don't think we have an exact target, but something a little north of 1.1 is probably the right number in the near term.

As I think we kind of hit it. There's no doubt the desire with increases in distribution per unit is to try to find a rhythm that we could get into with some regularity to it as opposed to just having it match one quarter's results.

The next question comes from Holly Stewart at Howard Weil.

First question maybe for Phil. So I guess could you just talk about the progress on the tax implications for the LDC sale, maybe any incremental thoughts about final sale proceeds?

No, we're not prepared to talk about that at all. We're still working through some of that. I think when we have the conference call for the deal, we talked about, I think, basis of $160 million, and we would expect to pay roughly 20% on deemed purchase price above that. But we're not really ready to say anything more about that. At this time, we're still working through some things in terms of like kind exchange, et cetera, and it's just too early to talk about it.

Okay, great. And then Dave, maybe you could comment on just kind of final use of proceeds after the LDC sale is finalized and then the drop-down process sort of begins?

Yes. I don't know that I have anything to add on what we would do with proceeds from the EGC sale. I'd still rather see that transaction go through the rest of the approvals. I mean, as you know, we did tend to focus a little bit more on the FDC approval only because of the unique history of these assets, but for the most part, what you focus on with gas utility M&A transactions are the public utility commission -- public service commission approvals, and we're still in the relatively early days of those. So we're still kind of working -- even though -- so, it's great for us that we're over this one hurdle that had been an issue in the past, but now it turns into a more standard LDC M&A process. So I just assume not get ahead of ourselves there. We're just trying to create value, monetize reserves the way we can, and I know if you're looking at acreage issues, it's mainly what we're prioritizing still, it's trying to see if there are opportunities to build around our current strong business. We're still in the so-called donut holes, those sorts of things.

Okay. I was just trying to -- I mean, it's a high- class problem to have, but just kind of thinking about as you enter 2014, you're going to have cash coming in from the LDC sale as well as the start of more significant drop-downs. So just kind of thinking bigger picture, again, high-class problem to have, but you will have a lot of incremental cash coming in the door.

That's true. And I guess the message that we're trying to send through is that we will be disciplined about capital. We've been disciplined about it for the last, geez, as long as I've been here, which is -- it's amazing but it's coming up on 15 years now. And we're not going to let money burn a hole in our pocket. That's kind of what we're focused on as much as anything is, a lot of these transactions are ones we enter into, because we think they're the right thing to do, not because we've got something else that we need to raise up and spend the money on. Look, I mean, and that's a couple of people pointed out, with more -- with some improvements and what the Marcellus results have been, with the Upper Devonian, et cetera, may well be the that there's other opportunities down the road to increase the development, but we just assume, take a look at that based on the operational results.

Absolutely. Okay. And then maybe, Dave, just a strategic update around that Huron asset process that's been ongoing.

Well, it is certainly true, notwithstanding my comments of the prior call or about the back end of the curve not really having moved up much, that the tenor of the discussions and the M&A front are probably a little brighter when you've got higher front month and front year prices. So we would certainly hope that we might be able to get something done, but I don't have anything in particular to report. Well, I guess one thing I will reiterate that, I think, we've said a bit is, at these prices, at least the Huron is economically -- it is economically attractive to invest. It's not as economically attractive to invest in the Huron as it is in the Marcellus, and of course we do have a higher cost of capital than the Sandy and MLP [ph] would have, because we enter into a higher-risk, higher-return type of activities than all those folks do. But it does clear our hurdle rates the way we have them set right now as a result of the increasing gas prices. So we're hoping that, that will lead to some opportunities along the lines that we've talked about strategically for the Huron, but we don't have anything to report on it right now.

This concludes our question-and-answer session. I would like to turn the conference back over to management for closing remarks.

Thank you, Amy, and thank you, all, for participating.