WPX Energy Management Discusses Q3 2012 Results - Earnings Call Transcript

| About: WPX Energy, (WPX)


Q3 2012 Earnings Call

November 01, 2012 9:30 am ET


David Sullivan

Ralph A. Hill - Chief Executive Officer, President and Director

Rodney J. Sailor - Chief Financial Officer, Senior Vice President and Treasurer

Michael R. Fiser - Senior Vice President of Marketing


Brian M. Corales - Howard Weil Incorporated, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division


Good day, and welcome to the WPX Energy Quarterly Conference Call. Today's call is being recorded. At this time, I'd like to turn the conference over to David Sullivan, Manager of Investor Relations. Please go ahead.

David Sullivan

Thank you. Good morning, everybody. Welcome to the WPX Energy Third Quarter 2012 Operational Update. We appreciate your interest in WPX Energy. Ralph Hill, our CEO; and Rod Sailor, our CFO, will review the prepared slide presentation.

Along with Ralph Hill and Rod Sailor, members of the senior management team, Bryan Guderian, Senior VP of Operations; Neal Buck, Senior VP of A&D and Land; and Mike Fisher, Senior VP of Marketing, will be available for questions after the presentation.

This morning on our website, wpxenergy.com, you'll find today's presentation and the press release that was issued earlier today. The third quarter 10-Q will be filed later this week, and that will also be available on our website.

Please review the forward-looking statements on Slide 2 and the disclaimer on oil and gas reserves on Slide 3. They are important and integral to our remarks, so please review them. Also included are various non-GAAP numbers that have been reconciled back to Generally Accepted Accounting Principles. Those schedules follow the presentation.

So with that, Ralph, I'll turn it over to you.

Ralph A. Hill

Thank you, David. Welcome to WPX's Third Quarter 2012 Earnings Call and thank you for your interest in WPX. A few reminders about WPX. We have strengthened our portfolio with 18.5 Tcf of 3P reserves and in an appropriate commodity environment, we can grow all 3 of our products, oil, liquids and natural gas, at a double-digit production growth rate for many years. In other words, we could double the size of our company within 5 years in the right environment and still have room to grow. Few companies with that kind of existing portfolio could accomplish this like we can. We have tremendous flexibility in the strength of our assets to ramp our capital up or down, depending -- without losing leases in value depending on commodity prices.

Our technical and low-cost leadership provide us strength in our operations. Our strong balance sheet of $1.7 billion liquidity puts us in a position of strength to grow at the appropriate time. And by choice and by design, this portfolio was set up to be in the best oil basin in the nation in the Bakken, the best gas and liquids basin in the Piceance, and the best gas basin in Marcellus.

I'm now on Slide 4, which it looks like it's already on Slide 4. Third quarter highlights. We continued to perform well in the face of 10-year low natural gas prices and a fall off in NGL prices. We've generated year-to-date adjusted EBITDAX of $744 million and on target for the full year adjusted EBITDAX in excess of $1 billion.

Very importantly, we're reaffirming our full year production guidance of the 1.38 Bcf a day for 2012 on equivalent basis. This is the guidance we gave in February when we were in the process of severely cutting our capital budget by $425 million in response to the decade-low gas prices.

For the year, we expect our natural gas production to be up 3%; our oil production on target at 40%; and liquid production up 5% from 2011. Each of these -- if you look at them specifically, we are on target for our oil production growth for the year. We were slightly behind in the third quarter on the Bakken, but I'll talk about that in a few minutes. We are ahead on natural gas production. We originally thought we'd be down slightly in natural gas production. We'll be ahead on natural gas production. And we're slightly behind on liquids. A lot of that was in the third quarter due to some flat turnarounds in maintenance, which we can also talk about in a few minutes. But on equivalent basis, we're right on target.

Our CapEx range is in step slightly to $1.45 billion to $1.5 billion, which is inclusive of the new oil projects, the exploration projects. And our quarterly growth in the Bakken was affected by completions that were delayed from the second quarter to late in the third quarter, very late in the third quarter.

Our third quarter average production of 9,600 barrels oil per day has already increased approximately 9% to October of 10,500 barrels oil per day, and we do expect to reach our planned December exit rate.

For 2013, we're deep into the process of our capital allocation process, which is based on rate of return. Our 3 core areas: The Piceance, the Bakken and Marcellus are competing for 2013 capital. They're based on returns, and we plan to publicly discuss our 2013 budget early next year.

We are pleased to see the recent recovery in natural gas prices, which enhances our low-cost Piceance value position and Marcellus position. We're one of the most operationally levered companies to recover in natural gas prices. The Piceance can be the first and fastest to grow volumes given our low-cost advantage, large drilling inventory, over 10,000 gross locations, and there are no infrastructure constraints in the Piceance. And Piceance has significant excess takeaway of 2.5 Bcf of excess transportation takeaways.

Slide 5. Looking at the Piceance, we spud 43 wells in the third quarter. We've seen a 50% increase in the number of wells we can drill per rig since 2007, so we continue to be much more efficient there. A couple of record wells have been drilled recently. In the Ryan Gulch, a record well was drilled in 8.5 days. With an average Ryan Gulch, wells are now 11 to 12 days. Just 3 years ago, we took 25 days to drill a Ryan Gulch well. Consistently drilling our Valley wells now at about 9 days or less, and we have a record Valley day of 3.8 days that we've drilled a well in.

We continue to add additional water handling disposal capacity, which does -- continues to what the Piceance does best, which is lowering costs. And we're clearing total depth on our first horizontal Mancos/Niobrara well, which I have more of this in the next slide.

We have -- we do have a prolific resource base in the Piceance without the Mancos of 12.2 Tcf, and that does not include the Mancos/Niobrara, but we -- again, I'll talk about that in the next slide.

And I'm very proud of our team for winning 2 awards for environmental protection recently through appropriate reduction in what we call our split-rig design and our waste minimization.

Slide 6. WPX is positioned, we believe, to grow rapidly when natural gas prices recover. As I mentioned, prices are up $0.34 or 9.5% to $3.90 from when our last call was. We believe we're positioned to grow rapidly, and Piceance side rigs -- size rigs will be available versus rigs required for the horizontal gas plays.

As you can see of this graph, we have rapidly grown before. We grew 157 Bcfe on the left-hand part of this graph in the Piceance from 2004 to 2008. And we can now -- we believe we can grow again. With less rigs, we're so much more efficient. This time, we'd have 17 rigs to do this versus 26 rigs. We're not at 17 rigs, we're at 5 rigs, but it just shows what we could do when gas prices recover. And again, we could grow almost exactly the same we did last time at 155 Bcfe.

In the Piceance, we have advantage of a very large permit inventory in hand and ready to drill, and those permits are 2-year-type permits. Infrastructure and capacity is in place. The team is highly experienced, very talented drilling staff, has done it before, lowest drilling completion operating costs in the basin and we have available rigs. So we believe, with our people and our knowledge and when the time is right, the Piceance will recover fast as many of the gas basins.

Slide 7, let me remind you that we already control this resource and that we -- in the Piceance, we have significant upside in what's called the Mancos/Niobrara formation. It is a gas formation in this particular part of the basin, with 168,000 net deep acres. There have been 35 wells drilled by other operators. It's one of the few times in the Piceance we've let other people go first, and we're enjoying what they've done. They're de-risking the play for us. The wells are being reported in 6 Bcf range. We believe we have 20 to 30 Tcf of unbooked resource potential, and none of that is included in our 18.5 Tcf of 3P reserves and/or none of that is also included in our 10,000 remaining Piceance traditional locations. So we have a lot of opportunity here.

We did a vertical well in 2011 and tested 2 zones, and we have other zones we can test. And both of those zones have very strong results with IPs of 1 million plus a day.

We did spud our first horizontal well in August of 2012. We've obtained 535 feet of core and specialty logs, which we think will really help us in the future. We expect to TD this well in mid-November, begin completion the first week in December and we'll have results to discuss in the first quarter of 2013.

Slide 8. Turning to the Bakken, we currently have 5 rigs running the Bakken. As you know, we dropped a rig during the quarter for efficiency purposes. We are gaining -- and speaking of efficiency, we're gaining efficiency and we expect to complete 14 wells in the fourth quarter, and that's a significant improvement of what we've done for the year. Of the year, we've only completed 22 wells in the first 9 months, so we'll have a lot of activity in the Bakken in the fourth quarter.

We continue to delineate our acreage and now have only 5 wells left to drill, to hold all of our acreage by production. That will allow us to move next year and later this year to much more efficient pad drilling.

In the third quarter, we had some delineation in our areas in the southern part, which is depicted by the light green. We've had a well come in above expectations. It looks like it's going to be about a 740,000 barrel reserve well versus expectations that were in the lower 600s.

On the eastern part, the light red, we have drilled some wells there and are waiting on completion. And the Western delineation is in light blue, that is also awaiting on completion.

So in addition to having all of our wells drilled, or all of our acreage held by production by the end of the year or early next year, we are -- also delineated a major part of our acreage.

I want to also point that the Bakken West Texas differentials have improved from what was $17 in the first quarter to approximately $10 in the third quarter, and it's about $13 in the second quarter. October basis currently is only around $2, and we expect the balance of the year to trade about $4 or so. This dramatic improvement is due to the improved takeaway capacity at the basin. Primarily rail tech takeaway capacity has grown from 275,000 barrels a day to approximately 730,000 barrels a day, and most of this growth has occurred in late second quarter and early third quarter.

We also [indiscernible] that LLS and WTI spread has widened, from $12 in the first quarter to $20. So it makes a very competitive alternative to rail and what we try to do mostly with.

Our outlook in 2013 supports a differential in the $5 to $10 range, so we continue to see improvement in the basis differentials there. And we also have a science project under way, which I'll talk about in the next slide, Slide 9.

Well, we've had a successful infill density project, which is validating our resource. The purpose of this slide and purpose of this project has been -- and it has slowed us down somewhat in the Bakken and delayed some things, but we think it's absolutely the right thing to do. We want to understand the potential to increase the number of drilling locations and reserves. I want to optimize our infill density. We've only drilled 10% of our locations so we have 9% plus of our locations remaining to be drilled. And what we know about today, that could go up if -- obviously if we do have the ability to do any additional infill drilling and additional drilling in other areas.

We want to optimize our completion and designs. We want to understand our geological success factors, and we are in the processes for initiating our multi-well pad operations.

Status of the project is, all these 4 Middle Bakken and 3 wells have been drilled and will be on production in October. There's -- are on production this month. We drilled 4 Middle Bakken and 3 Three Forks wells on a 1,280-acre unit. It's our best well drilled, which is why we're optimistic about going forward. It was 19 drilling days, and we averaged on the pad 26 drilling days and 1-day-type moves.

We had successful data acquisition with 372 feet of core recovered. We cored the entire Bakken Formation: the Upper, the Middle, the Lower and the Pronghorn. We cored the entire Three Forks Formation, all benches, all 4 benches. We also cored a portion of the Lodgepole and the Birdbear Formations. So we have a ton of data that we have that will be coming in. And we had seismic and specialty logs shot obviously during this time. So production is recently online, and we should have initial -- some of our initial study results in the first quarter of 2013. But keep in mind, this will be a long-term project that will allow us to do quite a bit with the vast amount of locations we have left.

Slide 10. As I mentioned, our production in October has already increased 9% from the third quarter average, and our efficiencies are beginning to kick in with 14 completions scheduled in the fourth quarter versus 22 in the first 9 months of this year.

And if you look at this slide, on a BOE per day basis, our production should increase about 19% in the fourth quarter from the third. So we expect quite a bit of production increase in the fourth quarter based on these completions. You can see the rapid growth we've had. Keep in mind, we didn't take over operations of this asset until late in the second quarter of 2011. So we had tremendous growth since that time.

Slide 11. Looking at the Bakken costs, we've generally been drilling one well per pad, as you know, and these initial wells have been bearing the upfront infrastructure costs, which includes the pads, the roads, all facilities.

Looking at this slide, we've detailed our expected cost savings from transitioning in multi-well padding, pad drilling, improved service delivery and reduced service costs. We've also successfully negotiated lower service costs here in the Bakken during the third quarter, and these benefits will start to showing up in the fourth quarter.

We're staying with our previously communicated targeted well cost of $10.5 million. And keep in mind, we do use ceramic. As our operations mature and the transition to pad drilling takes place, which will be -- prevail across of our next -- all of our operations next year in the Bakken.

We did reduce our well count to 5 to narrow our focus and resources and make sure we give folks some expected improvements. And another thing we have that will be completed in the fourth quarter is our Van Hook gathering system will provide us initial savings of $2 to $4 per barrel and ultimately, savings from -- once the pipeline from our central delivery point at Van Hook install is completed, which will be in the first quarter of 2013, will be more like a $4 to $5 per barrel savings. So things will continue to get better in the Bakken.

Looking at the Marcellus in Slide 12. Our WPX model efficiency -- efficiency model is really taking hold in the Marcellus, transitioning to 3 fit-for-purpose rigs. We have 1 rigging up, 1 that's on and 1 coming still. Our move times have been cut by as much as 30%. We've had a 35% drop in completion costs from the fourth quarter of 2011 to third quarter of 2012.

Our net production did increase, only 3% from the second quarter to third quarter, despite even higher Laser line pressures than we had in the second quarter. We estimate at least $30 million a day of net production, is constrained by infrastructure still. I'm very happy to say at least some of our compression projects have kicked in and our first WPX pad compression project doubled our volumes on that particular pad in Susquehanna late in the third quarter.

Now let's turn to the next slide and talk a little bit more about that. This compressor started up on September 26 and as you can see, the average production from the wells on this pad doubled from 5 million a day to 10 million a day, and they've stayed flat. We believe that we have additional one -- we have one more pad that we can do this with, and we're just now starting it up and we expect similar results. Unfortunately, we're not going to do this on all of our pads because we expect and believe that Williams will be able to -- for the bigger volumes growth, we'll install a field compression that's scheduled for startup hopefully by the end of the year end. And as you know, Williams bought the Laser system. And that compression should be in by the end of the year, we hope, or early next year.

You can see just one example of how the production responds to lower pressure, and we believe we can actually lower the pressure further. We could have lowered it further during the quarter, but there was a one-in outage and there also was some maintenance in one of Williams' compressor statement -- stations.

Looking at Slide 16 (sic) [Slide 14]. One more thing on the Marcellus. Our spud to rig release times actually went up slightly in the third quarter from second quarter with the start of the Orion rig that went from 16 days to 17 days, but we're already back down to under 15 days. Typically, with a new rig, and the new rigs, it takes a well or 2 to get back -- get to where you want to start moving, and we're under 15 days. We did shatter our drilling record time of 14 days in the third quarter, with a new a record of 11 days on a 4,300-foot lateral. I've mentioned the collision costs were down significantly. And the Marcellus, to me, with the deficiency starting to kick in, is a great example. Our transport, our Piceance model, our knowledge into a new area, and we expect this to occur in the Bakken also.

Apco, very quickly. Traditional drilling is meeting expectations. We did establish some productivity from the Vaca Muerta shale with 2 frac-ed vertically drilled wells. To truly prove up this resource, it will take horizontal drilling. The environment, as you know, in Argentina is challenging currently. And we have one more concession to get done, which we expect to be accomplished in the first half of 2013 in the Rio Negro province.

Columbia, we've had 2 consecutive discovers -- discoveries in the Llanos basin. The first well is producing about 3,500 barrels of oil a day. We have a 20% interest in that. The second well is in the process of being tested, and we'll have additional prospects drilled in 2013.

And on Apco, from a production and earnings standpoint, through the second quarter, Apco was tracking towards a record year in production and record year in earnings. And things continue to go well from that standpoint.

Now I'll turn this over to Rod for the financial update.

Rodney J. Sailor

Thank you, Ralph. Turning to Slide 17. Comparing third quarter 2012 to third quarter 2011, results were impacted by lower realized prices across all of our commodities. We continue to face a challenging liquids environment, further impacted by constraints on the mapple [ph] system, which has resulted in reduced fractionation of ethane at the Meeker processing facility. We've also seen volumes impacted in the third quarter due to some plant turnarounds at Willow Creek in July. And then we also will continue to have some higher processing costs related to Willow Creek until those charges step down in 2013.

Third quarter revenues were also impacted by net -- $21 million net loss associated with derivatives not designated under hedge accounting. These are largely oil. If you'll recall, we recorded significant gain in the second quarter for the 9 months -- first 9 months in 2012, we have approximately $63 million in net derivative gains.

Also, our year-to-date results were impacted by $117 million in impairments related to decline in forward natural gas prices. These were recorded in the first and second quarters, and we had no impairments in the third quarter.

For the third quarter, WPX's overall production on equivalent basis averaged 1,359 million cubic feet per day, which was down 2% from a year ago. As Ralph mentioned, this decrease was a planned response to lower gas prices that we anticipated for this year. We generated $230 million in EBITDAX for the third quarter. I'd expect to generate over $1 billion for the year.

Our adjusted net loss for the quarter was $47 million versus $14 million of adjusted net income for the same period in 2011. Adjusted net loss for the 9 months was $84 million versus net income of $55 million for the same period last year.

I would point out even though we had lower production on a per-unit basis, we did manage to keep a number of our key costs flat or experience a decrease.

Capital spending in the third quarter was $337 million. And with 2 months left in the year, we expect 2012 spending to be approximately $1.5 billion. I think we said on the second quarter call that we were targeting $1.4 billion, and that would be a challenging number. I think we really feel strongly that we're going to get in at under $1.5 billion.

Slide 18. Liquidity at the end of quarter was approximately $1.7 billion. This was comprised of available cash in our undrawn $1.5 billion corporate credit facility.

Turning to Slide 19, just looking quickly at a summary of our hedges. As we've said repeatedly, we like to target about 50% annually, hedging about 50% annually of our production. For the balance of 2012, we've got about 59% of our gas production hedged, with fixed price swaps at a weighted average price of $5.06. We've got about 72% of our crude oil production hedged through a combination of fixed price swaps and costless collars. The average on the fixed price swaps is $98.20, and the range on the costless collars ranges from $85 to $106. About 15% of our liquids are hedged, with fixed price swaps at $50.74 a barrel, remind you that we hedged the individual -- we hedged the components individually.

We're also on this slide showing you a snapshot of where we stand for 2013. We had indicated that we were kind of looking for a $4 price target on natural gas. When the prices jumped up early October, we did start layering on some hedges. And you can see, we've got some -- and then for -- on the oil side, we've got some very attractive hedges on our crude oil production. Our gas production is hedged with fixed price swaps at an average price of $4.23. We have some additional volumes capped at $4.05. Greater than 50% of our crude production is hedged with fixed price swaps at a little over $100 and we've got some additional volumes capped at $108.

With that, I'd like to turn it back to Ralph to close out the call.

Ralph A. Hill

Thank you, Ron. Looking again at WPX and why invest in WPX, we are a top 10 domestic gas producer. We're actually -- about 80% of our production is gas. We have -- we are in the process of transitioning to some oil and more oil and more liquids, but we are a gas producer and we believe we're exposed well to gas as gas prices recover. We believe the low-cost, liquids-rich Piceance basin will grow first and fastest when gas prices do recover. And we have additional exposure, not in any of our numbers, in the Mancos, both in the Piceance and the San Juan Basin, which adds resource potential about 22 to 33 Tcf.

We do have increasing oil exposure and ability to grow NGLs. Our domestic oil production, we expect will continue to grow at a compounded average growth rate through 2015 at 25% to 30%, a significant growth rate on a compounded annual growth rate.

Our domestic NGL production is more than 29,000 barrels a day, and we have ability to grow that by 50% in 2014 with the planned expansion of what happened in the Piceance. So we have ability to grow our liquids significantly. And we did recently announce $100 million capital increase for oil-focused exploration activities. We should have some results to talk with you about by mid-year 2013. Thus, we expect to be able to tell you what we have at that time.

We do have an improving cost structure. I think this is very important, so I'm not going to read every bullet here to you. But on an annual basis -- if you look at our annual basis, by the fourth quarter of 2013, our cost structure improves by $117 million. And when you look at that on an annual basis, by the end of 2014, it improves by $205 million total. So significant cost improvements coming to WPX. These are already contractually done or being built or automatic improvements, so those will be happening for us: $117 million by the end of '13, $205 million by the end of 2014.

Our balance sheet remains very strong with superior credit metrics. We have demonstrated willingness to divest in non-core assets. We did the Barnett/Arkoma sale in April of this year, and we have some other assets that are not, if you will, winning the fight for capital. So we'll be continuing to look at those assets where their best place is. And thus, our CapEx is focused on the highest return core areas and emerging oil plays: so Bakken is oil-focused, Piceance is low-cost and liquids-rich, and Marcellus is our highest dry gas EURs. So we have 3 great basins to deploy our capital in.

With that, I appreciate your interest in the company today, and thank you for your interest. And we'll turn it over to David and to the operator.

David Sullivan

Yes, I think we're ready for the Q&A portion.

Question-and-Answer Session


[Operator Instructions] We'll hear first from Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

A couple of questions on the Bakken. I mean with productions relatively flat, is that just timing of completions? Anything happened during the quarter that may have caused that? And two, kind of where you stand on the cost side? I think last quarter, you talked about the $12.5 million cost. Have you seen an improvement from that -- to that yet?

Ralph A. Hill

Yes, Brian, this is Ralph. We basically have -- the majority of our completions were delayed until late in the third quarter. And that was just a function of really some of the drilling problems we had in the second quarter. So we had -- we really didn't have the completions that were done and were done very late in the quarter, and that caused the volumes to basically flat. And as you saw or hopefully heard, we're going to have 14 completions in the fourth quarter, and that's very close to how we've done for the full year, which is 22. So we expect our volumes to ramp up significantly. And we are just now beginning on the cost improvements -- we have seen some cost improvements recently on the completion side. Those are kicking in. We're not at pad drilling with the exception of our science pad, and that pad had 7 wells drilled on. But we spent a lot of time on that. We did a lot of coring, so that wasn't a well improvement, if you will, on cost. So we really think the drive to get to the $10.5 million or lower our well costs will kick in more at the beginning of the year, end of the year. So at this point, we're still -- the wells we had drilling were completed. There were already some of the problem wells, so those wells' costs didn't come down. We expect to do a little better in the fourth quarter. And then when we get to full-pad drilling and our service costs are lower and then those things happen or all of the rigs are fit for purpose, we expect to see the drive to cost really kick in more towards the next year.

Brian M. Corales - Howard Weil Incorporated, Research Division

And just another question, I know you're still kind of going through the budget process. I mean, can we assume it's going to be a relatively flat drilling budget? What's -- or maybe we can say the current rig count is relatively flat going into '13? Is that a safe assumption? Or is it all based on kind of expected cash inflows? How should we think about that?

Ralph A. Hill

Well, if we are in a $4 environment and 0-oil environment, we'll look a lot like this year, and then since -- hopefully a little bit higher. EBITDAX will be closer to what we thought it might be in that $1.2 billion to $1.1 billion range. So if that's what it is, then we'll look a lot like this year. However, the Bakken team has to do better. The Piceance team has to do better, the Marcellus team has to do better on the allocation of -- where we allocate our capital. But assuming they can do better and they do well, then we'd look a lot like this year.


We'll take our next question from Matt Portillo with Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

A few questions from me. You mentioned at the end of your prepared remarks asset monetizations, and I was wondering if you could walk us through which assets in your portfolio you view as non-core, and if you are currently in the process of looking at divesting some of these assets? I think we saw a CBM deal this morning and was curious as to how that might look relative to your asset base today.

Ralph A. Hill

Well, at our last conference we had, we had the -- a slide that talked about the core assets and we had other assets as we call it. And the assets that aren't winning the fight for capital in our portfolio currently are the Powder and Apco. Both of those, we will be willing to discuss with our board the right process to handle those assets. So we don't have anything ongoing right now. But clearly, we have a history and a track record of, if we have an asset that's not contributing to the portfolio, we're not going to sit on it for a long time. So nothing announced yet, but those are the type of assets that really aren't core to our portfolio at this point.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And then as we think about your emerging oil play, could you give us an update on maybe where that's located? I know you're waiting kind of for well results to actually talk about the physical play itself, but just curious if you could give us an idea of what region that is and/or maybe what formation you're looking at potentially testing?

Ralph A. Hill

It's -- we're not giving that out yet, but we're more mid-continent and Rockies. Western is where we --and we have several plays we're involved in. And at this point, that's all -- and we're still actively involved in it, so we want to kind of keep it that way for now.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then just 2 quick questions for me. I think you mentioned there was some processing plant downtime which may have affected your NGL volumes. But just curious if you could give us a little bit more color on kind of the decline quarter-over-quarter on NGLs, and how we should think about those volumes going into Q4 and maybe into 2013?

Ralph A. Hill

Yes, I'll give that question to Mike Fiser.

Michael R. Fiser

This is Mike Fiser. The third quarter volumes for NGLs were impacted negatively, primarily at Willow Creek. We had a plant turnaround in July 7 to July 12, the entire plant was shut down. And then as well, we had some maintenance that we experienced on Overland Pass Pipeline. Those 2 events reduced our NGL barrels by about a little over 100,000 barrels in the month of July. And then in addition to that, we continue to suffer from some reduced ethane extraction at Meeker. Currently, we're recovering about 50% of our ethane in the third quarter. Compare that to the first quarter, we recovered about 75% of our ethane through the Meeker plant. So that was about 60,000 to 70,000 barrels a day at Meeker. So you combine those 2 issues and we're looking at about 170,000 barrels total that was -- that we were impacted in the quarter.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And final question for me. Could you just talk a little bit about your gas realizations? Just -- our kind of view is it's maybe been a little bit weaker than expected, and I was just curious was there anything in particular that was affecting your gas realizations during the quarter?

Michael R. Fiser

Well actually, our realizations were up 20% from Q2, and the market itself was up that same amount. So we continue to track the market. Our basis to NIMEX, if you want to kind of look at the benchmark that way, was a bit wider in the third quarter. As you know, we're primarily a Rockies producer and the Rockies basis in third quarter weakened to minus $0.25, and in the second quarter it was minus $0.21. So there was some weakness there. But generally, we're tracking the market itself and overall, we were up. Of course, the hedge impact in the second quarter was a little greater than the third quarter, so our net price with hedge impact was up about $0.11 -- or 11%, excuse me, from quarter-to-quarter.


[Operator Instructions] And there are no further questions. At this time, I'd like to turn the call back over to our speakers for final remarks.

Ralph A. Hill

Thank you for your interest today in the company, and we look forward talking to you soon.

Rodney J. Sailor

Thank you.


This does conclude today's conference. Thank you for your participation. You may now disconnect.

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