W&T Offshore Inc (WTI) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen. Thank you for standing by. Welcome to W&T Offshore's third quarter earnings conference call. During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions.

(Operator Instructions)

This conference is being recorded today, [Thursday], November 1, 2011. I would now like to turn the conference over to Mr. Mark Brewer of Investor Relations. Please go ahead, sir.

Thank you, Operator, and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the results for the third quarter of 2011.

Before I turn the call over to management, I have a few items to point out. If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to the Investor Relations section of the Company's website at www.wtoffshore.com, or via recorded replay until November 8, 2011. To use the replay feature, call area code 303-590-3030 and dial the passcode 4480870 #. Information recorded on this call speaks only as of today, November 1, 2011 and, therefore, time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our third quarter 2011 earnings release for our disclosure on forward-looking statements.

Now, I would like to turn the call over to Mr. Tracy Krohn, W&T's Chairman and CEO.

Thanks, Mark. Good morning, everyone.

We appreciate you joining us for our third quarter of 2011 earnings conference call. Today, I have Jamie Vazquez, our President; Steve Schroeder, our Chief Operating Officer; and Danny Gibbons, our Chief Financial Officer. Other members of management are also here for the Q&A session that will follow. Jamie and Steve are going to walk through details of our operations in a moment, but I want to update you on the recent activity onshore.

First, we've been pretty busy with our drilling program in West Texas, developing our new Permian Basin acreage out there, and exploring in our Terry County acreage. With hundreds of potential future well locations, we are currently focused on determining the best methods for optimal drilling, completion, and production to maximize potential of this new asset. We have a team dedicated to the Permian. They're focused on maximizing the value of that. We made a visit out there just recently. I was pretty impressed; it's a large area. In total during the third quarter, we reached TD on about 19 wells. We're still drilling on a couple more. We drilled 8 more wells since the end of the third quarter. We should be able to drill or begin drilling on a total of 11 wells before the year is out.

We've also become very active in two distinct areas of East Texas. In one area, we recently acquired around 141,000 net acres, and we are completing our first well as we speak. In the other area, we have made a significant discovery, and should be able to announce the well results soon. We are expecting the well to come online producing approximately 20 million cubic feet equivalent per day of initial production in December of 2011. During the quarter, we closed on the final offshore Shell property. It was part of a larger package of properties that we acquired from Shell last November. In this transaction, we acquired the Fairway Field and the Yellowhammer Plant. We made an announcement on that earlier. The Fairway Field currently produces around 29 million cubic feet equivalent per day, which is flat with the rate it was last year when we negotiated to buy the Field.

Our proved reserves at mid-year, pro forma for the acquisition of the Fairway Field, were 740 Bcf equivalent, or 123 million barrels equivalent. This is the highest reported proved reserve amount in our Company's history. In fact, our reserve-to-production ratio, as a result of adding the Permian Basin properties, has increased from 5.6, at the end of 2010, to 7.7, based on these mid-year, pro forma reserves, and using production for the 12 months ended September 30, 2011. We set out to grow reserves and production this year, just like we always do, and we're definitely on the right track to accomplish those goals. Our proved reserves at the end of September, using SEC pricing, had a PB10 value of nearly $3 billion. That's up almost $1.1 billion since the beginning of the year. Our reserve mix is 58% oil and natural gas liquids as a percentage of the total proved reserves.

We had another really good quarter with higher production volumes, higher oil prices, and expenses in line with expectations. Our production was above the high side of guidance, primarily due to better well performance and less than anticipated downtime from tropical storm activity. Our realized oil prices were really strong again this quarter, as we continued to benefit from the premium that our Gulf Coast barrels are receiving relative to WTI. In fact, we are receiving around 90% of the Brent price on most of our Gulf of Mexico productions. Production for the quarter was 46% oil and natural gas liquids, and with oil prices averaging around $102 per barrel range for the quarter, that makes a pretty big impact on the bottom line. Our GAAP earnings for the quarter were $0.70 per share, which is up 94% from third quarter last year. Our clean earnings, or earnings excluding special items, were $0.56 per share, which represents an increase of 30% over third quarter last year, and above first call consensus earnings of $0.52 per share.

We'll talk a little bit about our budget. I know you're interested in our 2012 budget. We are finalizing that budget and plan to announce the 2012 budget in December. I believe that our 2012 budget, excluding acquisitions, will be up from this year with all the things that we are doing onshore; but we will continue to drill within cash flow. That's been the mantra for a long time. I see no reason to change that.

With that, I will turn the call over to Jamie.

Thank you, Tracy.

It's time to take a good look at W&T Offshore. Our reserves are up, our production is up, and our profitability is up. All year we have remained focused on our goal to profitably increase production and reserves. Thus far in 2011, we have closed 2 acquisitions, and we have participated in the drilling of 31 onshore wells and 5 offshore wells. All successful, except 1 onshore well. Based on these results, along with our published guidance, we expect to make our reserve and production goal a reality.

First, I'd like to update you on our activities in the Gulf of Mexico. The Gulf of Mexico continues to be an important part of W&T's asset base and source of exploration and development projects. In addition to our Fairway acquisition, our exploration and development program in 2011 have provided us with profitable opportunities, which have an excellent rate of return and low finding and development cost. To date, we have drilled 5 offshore wells, 2 currently drilling. 2 additional wells are planned for 2011. Our offshore exploration and development programs will continue to be an important part of achieving our production and reserve goals going forward.

During the third quarter, the Main Pass 108 No. 8 well was drilled. The well spudded July 24, and reached TD of 12,700 feet on August 8. The well was a development well, and found 3 primary pay sands. We expect to have the well online in the fourth quarter, and it should add approximately 5.4 million cubic feet equivalent net per day of liquid-rich production. We moved a platform rig on location at our 100% working interest Mahogany field in Ship Shoal 349/359 during September, and have drilled the Ship Shoal 359 A11 sidetrack. This was a development well, targeting oil in the P sand, which is the main producing zone in the field. This well should be online in the fourth quarter.

The Mahogany program is expected to be either a 3- or 4-well program, and should continue well within 2012. We project 1,400 barrels of oil per day and 2 million cubic feet of gas per day net average buildup from each of the wells in this program. In mid-September, a rig was moved on location to drill the South Timbalier 41 E1 sidetrack exploration well. This non-operated well is currently drilling, and we have a 40% working interest. At South Timbalier 314 field, we are drilling a development well. It's a South Tim 316A-3 sidetrack, where they operated the well, and we have 50% working interest.

For the remainder of 2011, we expect to drill or be drilling 2 more wells offshore, 1 of which is an exploration well and 1 is a development well, and we have 100% working interest in both of the wells. The exploration well is located at Mahogany, being Ship Shoal 359 A1 sidetrack, with the objective focus on the P sand; remember, this is oil. This well should be down by year end, and we are targeting 9.5 million barrels of possible reserves. The development well is located in Mississippi Canyon 243; it's the A4 sidetrack well in our Matterhorn field. The well is targeting multiple field pay sands. Steve will provide you additional details on that well later in the call.

As I mentioned in the last call, we had planned on commencing a deepwater well in 2011, but it looks now that, that well may not commence until second quarter of 2012 at the earliest. We continued to be active offshore in 2011 and would expect similar or increased activity in 2012. Now I'd like to discuss our onshore activity. Our current focus is on both the West Texas Permian Basin and East Texas. Our current Permian Basin activities are being conducted in several West Texas counties, with approximately 30,000 net acres under lease. Our expectation is that our lease acreage position will continue to grow.

We currently have 5 rigs running in the area, 3 rigs exploring and developing the 21,500 net acres we acquired in May, which we refer to as our Yellow Rose project; and 2 rigs drilling exploration wells on the 9,500 acres that we have acquired in Terry County. In our Yellow Rose project, the drill time in the area is running around 15 to 19 days to reach total depth, with some wells taking as little as 13 days to drill. The cost of each well to drill and complete is running about $2.1 million net. Not all the drilling is development. In fact, half of the wells that we will drill between now and the end of the year will add proved reserves. This is a low-risk operation with 450 to 500 drilling locations on 40-acre spacing. Our proved reserves are primarily based on 80-acre spacing, but nearby operators are drilling on 20-acre spacing, so it is very obvious that this project holds a lot of upside potential.

All the wells are targeting the Wolfberry Trend, but deeper targets have been tested and are producing. We have drilled and completed 21 wells since closing on May 11. We anticipate drilling 27 to 30 wells for the year, assuming that we run only 3 rigs. In Terry County, also in West Texas, our working interest varies between 35% and 100%. 2 rigs are drilling exploration wells there and, again, are focused on the Wolfberry Trend. Assuming a success case, we have over 200 locations on 80-acre spacing; and could potentially result in proved reserves of 11 million barrels of oil equivalent and more on a down-facing scenario. As discussed in our last call, we are evaluating potential horizontal well locations. Thus far, all of our wells in the Permian have been vertical wells with multiple stage frac completion. We are continuing to work on horizontal well design fracking and determining the most promising geologic areas.

Now let's shift across the state and go to East Texas and talk about that little bit. In East Texas, we have 2 prospective exploratory areas that we are currently pursuing. 1 area, which we refer to as our Star Project, covers approximately 141,000 net acres that we acquired in the third quarter. We operate and have drilled and are currently completing an exploration well on the acreage with 96.875% working interest. The well is a horizontal well, targeting a conventional reservoir Our success case in our Star Project is potentially about 300 Bcfe equivalent of liquid-rich gas reserves.

The second project area in East Texas targets both conventional and unconventional reservoirs. As operator, we have drilled a well, with a 35.4% working interest, to a total depth of 16,800 feet and found significant pay. Again, we believe this to be a significant discovery, and we expect an IP rate of 20 million a day equivalent growth production by year-end. We also believe there will be additional development opportunities in this area.

Let me update you on our capital budget. As previously disclosed, the capital budget for 2011 was $310 million, excluding acquisitions. Through the first 3 quarters, we have spent $185 million for exploration and development activities, which includes land and seismic purchases. We expect that we will spend the remainder of the capital budget before the year is out, and we currently have 8 rigs running, with 5 onshore and 3 offshore. On the acquisition side, we have spent $435 million through the first 9 months of the year.

In summary, these projects located in West Texas and East Texas could have tremendous upside for W&T, with about 900 drilling locations should the projects prove successful. We should have more details regarding the results of these areas late 2011 and early 2012, at which time we will provide you much more detail.

With that, I would like to turn the call over to Steve Schroeder to update you on the operational items.

Thanks, Jamie.

We continued to ramp up production this year from our acquisition, drilling, and development activity. Our goal in any acquisition is to take advantage of the upside and to find the overlooked and unexploited potential. We made progress during the quarter, and believe there is much more to do to enhance the value of our recently acquired properties. First, at Matterhorn or Mississippi Canyon 243, we continue to benefit from good well performance, as the field has produced better than our original projections. In July, we recompleted the A7 well, which is currently producing 11 million cubic feet per day and 450 barrels of oil per day net.

Also at Matterhorn, you might remember from our last call that I mentioned that we had entered into an agreement with a third party that will allow them to process their production at the Matterhorn facility for a fee. This will help reduce our cost when this production comes on line in the second quarter of 2012. This, along with 3 other processing deals we have negotiated this year, should provide an incremental cash flow next year of between $10 million and $15 million. Currently, we are continuing with our plan to sidetrack the A4 well at Matterhorn. Assuming we receive the permits as expected, we anticipate mobilizing a rig to the location in December, and should be drilling soon thereafter. We anticipate production buildup of approximately 2,700 barrels of oil per day net towards the end of the second quarter of next year.

Now, let me update you on our activities at Tahoe and Southeast Tahoe fields. If you recall, we discussed a compressor project at Main Pass 252, which is the host platform for the Tahoe production. This project will accelerate Tahoe and South-East Tahoe production, and will allow us to reduce the reservoir abandonment pressure. We have installed an additional compressor and will be modifying the existing compressor. We expect the incremental reserves from this project to be approximately 30 Bcfe gross. We have improved our marketing of the production by routing to a different gas plant, which increased the natural gas liquids received. The incremental increase in proved reserves was approximately 2.3 million barrels of natural gas liquids from the change in marketing strategy.

We had another active recompletion and workover program this year. Overall, through the first 9 months of 2011, we have performed 28 recompletes and 29 workovers offshore that added net initial incremental production of approximately 88 million cubic feet equivalent per day, at a cost of about $36 million. Regarding our onshore operations, in the Permian Basin, we have 4 to 6 drilling rigs and various workover rigs working on any given day. We've also assembled a dedicated team of professionals to run this operation and maximize the value of the assets. Since taking over operations, we have made a number of remedial changes and are continuing to evaluate the results to determine the best processes going forward. As we mentioned last quarter, we are working to improve -- and, in fact, have improved -- the casing design, pump jack size, rod design for wells, and altered the way in which wells flow back after fracking to reduce the flow back time to approximately 3 weeks. Also, we are working to install remote-control systems to monitor each well's lift system to reduce future workover expenses.

Our last 10 completions have had IPs of between 40 and 240 barrels of oil per day gross, with an average IP of about 90 barrels of oil per day gross. We are still in the R&D phase, if you will, and production from the Permian is not yet a large part of our total Company production, but we are committed to optimizing these assets and taking the steps necessary to maximize long-term profitability. We are producing anywhere between 2,750 and 3,000 barrels of oil equivalent per day. We've had some production downtime in the field due to workovers and other remedial activity. In addition, we've experienced some gas pipeline constraints, which caused us to flare some gas, but expect the bottleneck to be remedied by the beginning of December. In our Terry County exploration effort, we are building infrastructure to handle the production, Including non-operated wells, we have a total of 10 wells that have reached total depth, and we have 3 non-operated wells that are on flow back. We are fracking our first 2 wells in the area and are anxiously waiting on the results.

Let me move to production guidance. For the fourth quarter, we anticipate our oil and natural gas liquids production to be between 1.9 million and 2.1 million barrels, and our natural gas production to be between 14.4 and 15.6 Bcf; and our total production to be in the range of 26 to 28.2 Bcfe, or 4.3 million and 4.7 million barrels of oil equivalent. For all of 2011, we anticipate our oil and natural gas liquids production to be between 7.7 million and 7.9 million barrels, and our natural gas production to be between 53.8 and 55 Bcf; and for total production for the year to be between 100 and 102.2 Bcfe, or 16.7 million to 17 million barrels of oil equivalent. Our guidance for lease operating expense for the fourth quarter of 2011 is between $57 million and $63 million, and for the year between $217 million and $223 million.

We have increased our full year guidance primarily due to increased workover activity at our Fairway and Permian Basin properties. It's not unusual for us to have an increase in non-recurring expenses immediately after acquiring an asset. With the previous owner cutting expenses during the sale of the property, we typically have to spend some money upfront on workovers for repairing the facilities, which leads to fewer dollars spent in the long run. Our guidance for gathering, transportation, and production taxes for the fourth quarter of 2011 is between $6 million and $10 million, and for the year, $21 million and $25 million. This is a decrease in our annual guidance.

Now, let me turn it over to Danny to discuss our third quarter results.

Think you, Steve.

Revenues for the third quarter were $245.4 million. That's up $75.8 million from third quarter last year, due to higher oil prices and higher production volumes. Just like in the second quarter, we greatly benefited from higher oil prices, which, when coupled with higher production volumes, led to higher earnings. Crude prices averaged over $102 per barrel during the third quarter of this year, and that's compared to $74.46 per barrel in the third quarter of last year.

As Tracy mentioned, pricing for our Gulf Coast production is much closer to Brent crude prices rather than WTI, which continues to provide a real boost to our realized pricing. Not only were our realized prices higher in the quarter, but our production volumes were up as well. For the quarter, our crude oil production was 1.5 million barrels, our NGL production was almost 501,000 barrels, and our natural gas production was 14.3 Bcf. On a natural gas equivalent basis, production was 26.5 Bcfe, which was up over 22% compared to third quarter last year, and 6.6% sequentially. Let me move on to a discussion of lease operating expense.

As you've heard me describe in the past, we think of LOE as 5 different components, including base LOE, insurance premiums, workovers, facilities work, and hurricane remediation to the extent that exists. For the third quarter, LOE was $58.9 million, and that compares to $34.4 million in the third quarter of last year. Base LOE was up $10.1 million with the addition of all the deepwater properties, along with the Permian Basin and the Fairway Field additions. Insurance premiums are up due to the insurance renewals associated with the substantially expanded coverage as a result of recent acquisitions both onshore and offshore. Workovers increased $4.3 million, with the work at our newly acquired Permian Basin properties and various offshore projects. Hurricane repairs, net of insurance reimbursements, changed $6.6 million, as the third quarter of last year had a $7.5 million insurance reimbursement that did not reoccur in the third quarter of this year.

DD&A for the third quarter on a Mcfe basis was $3.19, and that compares to $3.48 in the third quarter of last year. The DD&A rate decreased with the substantial increase in proved reserves. On a nominal basis, DD&A was $84.5 million, and that's an increase of $9.5 million over the third quarter of 2010 due to higher production volumes. General and administrative expenses were $18.1 million in the quarter, and that's up $4.7 million from the third quarter last year. The increase in G&A relative to last year is primarily due to higher incentive compensation associated with the achievement by the Company of predetermined performance targets, and then, obviously, expanded activities onshore and offshore. Our guidance for G&A expenses for the fourth quarter of 2011 is between $19 million and $21 million, and for the year between $73 million and $75 million.

As you've already heard, we've had another really solid quarter operationally that translated into really good financial results. For the quarter, our reported net income of $52.9 million or $0.70 per share was up considerably from the $27.2 million or $0.36 per share recorded in the third quarter last year. Adjusted to exclude special items for the same periods, net income was $42.4 million or $0.56 per share, compared to $32 million or $0.43 per share in the third quarter of last year. Also keep in mind that our effective tax rate for this quarter was 35.3%, and that compares to only 2.4% in last year's third quarter, when we had the reversal of valuation allowance throughout 2010. The special items are explained in our third quarter earnings release.

Adjusted EBITDA was $161.5 million, and that's up $43.6 million from the third quarter of 2010; and our adjusted EBITDA margin was 66%. Year-to-date, EBITDA is over $470 million, and that's up 43% from the $328.6 million reported in the first 9 months of last year. Net cash provided by operating activities for the first 9 months of this year was $396.1 million. That compares to $392.9 million for the same period 2010. Please keep in mind that we received a tax refund from the United States Treasury of almost $100 million last year, and it paid out $25 million thus far this year. Otherwise, cash flow from operations is up $128 million, with the higher production volumes and higher realized sales prices.

Also keep in mind, the net cash provided by operating activities is reduced by plug and abandonment expenditures. For the first 9 months of 2011, such expenditures were $51.3 million, and insurance reimbursements related to P&A work was $18.9 million. Such amounts for the comparable period of 2010 were $62.6 million and $46.9 million respectively. We expect to make additional recoveries in the future, as we perform plug and abandonment work of facilities and platforms that were damaged during Hurricane Ike. Moving on to the balance sheet, our net cash balance at the end of September was $7.7 million, and we had $94 million drawn onto the revolver. Our borrowing base was recently increased to $575 million, so our liquidity continues to be sufficient to allow us to continue to pursue the growing list of opportunities with offshore and onshore.

Talking about the effective tax rate -- for 2011, our effective tax rate will be in the range of 35% to 36%. Virtually all of that is going to be deferred, except for amounts related to alternative minimum tax, which required a small cash payment. The effective tax rate reflects not only the federal statutory rate, but also an amount for state taxes related to our Permian Basin production. Our effective tax rate is up considerably from last year, again, when we were able to completely reverse the previously established valuation allowance, which reduced tax expense throughout 2010. Finally, I want to tell you that no changes were made during the third quarter to our hedging positions, which are all oil related.

With that, I'll turn the call back over to Tracy for closing comments.

Thanks, Danny.

Thus far, it's been a pretty great year for W&T. Production's up, reserves are up, we've had some great acquisitions, and great success with the drill bit onshore and offshore. In spite of war, insurrection, the European and American debt crisis, the lowering of our sovereign debt rating, and the aftermath of a massive disaster in the Gulf of Mexico, our share price, as of yesterday, was up from the beginning of the year by a considerable amount. I know it from the commitment of our employees and management that we have achieved success this year, and from the simple truth of not being over-levered.

We have entered the Permian Basin successfully, and intend to have, yet, a larger presence there. We've entered successfully into East Texas, with what we expect to be positive production and drilling results in the near term. We expect to be actively drilling and acquiring in the Gulf of Mexico, as always. We have the versatility to do that both in shallow water and deepwater. We look forward to presenting investors, would-be investors, and markets with more good new soon.

With that, I will take your questions.

(Operator Instructions)

[Yik-tat Fung], Jefferies & Co.

Good morning. Congratulations on a great quarter.

Thank you, sir.

Just a couple of quick questions. I was wondering if you could give us more color on what reservoirs you're targeting in East Texas? Are you targeting the Deep Bossier gas?

That's a really good question, Mr. Fung. However, I'm not prepared to answer that at this point in time.

Okay. Is there a possibility that you give us a sense of where geographically, county wise, that your acreage is?

Yes, there is a couple of different acreage areas. 1 of them over around St. Augustine, something like St. Augustine or Leon County, and the other one is, I guess, Leon County, yes.

Okay. And what is the well cost for these exploration wells?

Around 4-ish, for the shallower one, and probably 6 or 7 for the deeper one.

Thank you so much.

Mike Grijalva, Global Hunter Securities.

Thank you. Good morning, guys, and thank you for all the color. Tracy, just a quick question on the Star prospect. Have you guys closed that acquisition?

Yes.

Okay. And I was looking at some permitting data, looks like you guys might be targeting the James Lime out there. How many wells have you guys drilled and are all these vertical wells?

Once again, you're asking me to specify a certain reservoir and I'm not prepared to do that. But the answer to your question whether it's a vertical well or not is no, it's not. It's a horizontal well.

Okay, thanks guys. Congratulations.

Sure, thank you.

Noel Parks, Ladenburg Thalmann Financial Services.

Good morning.

Good morning Noel.

Just a couple things, kind of related. Could you -- there's a bit of a mention of workover expenses that you had in some of the newly acquired properties, and I just wonder if you could talk a little bit more about the sort of things you are doing, and over how long, how many quarters, you expect to have those sorts of expenses?

Yes, I presume you are talking about the increased costs and LOEs in workovers. The reality is that when we do one of these large acquisitions, normally the seller is in a position of -- he really doesn't want to spend any more money, money that is being spent on maintenance and routine things that they might ordinarily do in preparation for the sale. So, you show up and things aren't running quite the way you want them to, so we spend money on the front end to help us get that back to a more normalized operation and save us a little money on the back end. It includes rod failures. We had some pumps that we had to lower. We had some fiberglass rods that we had to swap out. There were some scale issues. There were some paraffin issues over in our Permian Basin area, and that was probably the majority of it.

Okay, great. And another more financial question. I'm sorry if I missed the discussion of it, but the differentials look like they were not quite as favorable as I had thought they might be on the oil side during the quarter. Was there any fluctuation or did anything unexpected happen or could it have just been that my math was off?

I can't really answer as to whether your math was off, Noel. I mean, there is fluctuation during the quarter, naturally, because of the fluctuations that we had -- if you may recall, the last time we did an earnings conference call, the markets in Europe were tumbling. In fact, it was the first time we'd ever had a conference call where nobody asked a single question. They were all off at the trading desk trying to figure out what was going on, and we are kind of having a similar day today, but prices dropped a little bit during that time, then they went back up, then they dropped again, then they went back up, and right now, they are dropping again. I think it's just, more or less, natural fluctuation, and it may have caught you out a little bit on assuming an average.

Okay, but not real different from what you had assumed going into the quarter then?

I don't think it was a real different. Danny, you got anything to add to that?

Mark and I were talking. It may be a little bit because the NGL volumes are up. And so when you start to try to model those 2 together, you may be getting a little bit off because of NGL's and I can follow up with you -- Mark and I will follow up with you after the call to see just exactly what your math is and just to make sure you are on the right track, Noel.

Actually, thanks, that would be helpful because that is something I hadn't really taken into consideration was the NGL volume that wouldn't necessarily be apparent. Thanks a lot.

Thank you, sir.

(Operator Instructions)

Liam Kelly, Howard Weil.

Good morning, and congratulations on a very solid quarter.

Thank you, sir. We appreciate it.

Just had a quick question regarding production breakdown for the quarter. I was hoping -- I was wondering if you could provide any color as to the production breakdown by area. Similar reasons for the prior caller's question. I'm looking to be able to model out for pricing assumptions moving forward. I'm trying to get a grasp as to what's being priced off of WTI, LLS, et cetera

Okay, you've stumped me there. First of all, you have to give me an idea of what areas you're thinking about.

I'm just more looking for, how much -- the exit rates for the quarter, in terms of how much production you're getting from your Permian assets, how much from your offshore stuff, out of that gross production number that you reported.

Right now, we are producing 302 million or 303 million a day equivalent in net total. We've got about 3,000 barrels or so a day over West Texas, and that's the current breakdown. And as an addition to that, we are getting ready to bring some production on in East Texas, which we are trying to change those ratios a little bit as well. We have about 29, 30 million a day over in Mobile Bay. I think we mentioned that, that production is about flat with what it was the previous year.

Okay, great. And, could you provide any color as to any expectations for fourth quarter [exit]rates in those areas?

Well, no, I haven't broken it down by area. The guidance is pretty clear, but I don't expect any dramatic changes other than over in East Texas at this point in time. Oh, we will have some more production coming out of Main Pass, as well. We should have some of that new production online here shortly, as well.

Okay, great. And then just a quick follow-up to the NGL commentary that was just made. Can you offer any kind of breakdown as far as where the NGL production is coming from, whether it be from the Wolfberry wells or from -- how much of it is from Wolfberry and how much of it is from offshore?

Yes, it's almost all offshore.

Okay great. Thank you very much for the color.

Thank you, sir.

Thank you and there are no further questions at this time. I would now like to turn the call back over to Mr. Krohn for closing remarks.

Thank you, Operator. I think we are done. We will talk to everyone here shortly.

Ladies and gentlemen, this concludes the W&T Offshore's third quarter earnings conference call. If you'd like to listen to a replay of today's conference please dial 303-590-3030 with the access code of 448-0870. ACT would like to thank you for your participation. You may now disconnect.