W&T Offshore, Inc. (WTI) Q4 2011 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the W&T Offshore's Fourth Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, February 24, 2012. I would now like to turn the conference over to Janet Yang, Finance Manager, W&T. Please go ahead, ma'am.

Thank you, operator, and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the results of the fourth 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 a recorded replay until March 1, 2012. To use the replay feature, call (303) 590-3030 and dial the passcode 4506374 followed by the pound sign. Information recorded on this call speaks only as of today, February 24, 2012, and therefore, time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our fourth quarter 2011 earnings release for a 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, Janet, and good morning, everyone. We appreciate your dialing in for our year end 2011 earnings conference call. With me today are Jamie Vazquez, our President; Steve Schroeder, our Chief Operating Officer; and Danny Gibbons, our Chief Financial Officer. Jamie and Steve are going to walk through the details of our operations in a moment, while -- excuse me, Jamie and Steve, right? Yes. While Danny will cover some of the financial highlights for both the quarter and the year. First, I'd like to review some of the highlights for 2011, including our year-end reserve report and also, I'll discuss our capital budget for 2012. 2011 was another outstanding year for W&T. We delivered on our commitment to increase reserves and production. We continued to do a great job of generating cash flow. In fact, our operating income in 2011 was the highest in the company's history, and adjusted EBITDA grew 44% to over $646 million. We executed a successful drilling program of 54 wells, with a success rate of over 98%. And we also successfully closed 2 acquisitions, totaling $437.2 million, and achieved an all-in reserve replacement cost of $13.80 per barrel of oil equivalent. Even though we've had a consistently high oil component throughout the past 5 years at year end 2011, we are an oilier company, with oil and NGLs representing 59% of our proved reserves. And after acquiring approximately 173,000 net acres onshore, we've diversified the company's portfolio. Our proved reserves increased 44% to almost 117 million barrels of oil equivalent, with a reserve replacement ratio of 312%. Our oil and NGLs represent 59% of our total proved reserves, up dramatically from 47% last year. And needless to say, these are high-value reserves. PV-10 of our proved reserves increased to $3.1 billion, which represents a $1.2 billion increase over the prior year. In addition, our probable reserves at the end of 2011 were 63.1 million barrels of oil equivalent, and our possible reserves were 94.6 million barrels of oil equivalent. Keep in mind that these are third party engineered numbers. For the year 2011, production was 46,400 barrels of oil equivalent per day or 278.2 million cubic feet equivalent per day, and that was up 17% over last year. Production was split 47% oil and NGLs, and 53% natural gas. Our average realized sales price for oil was $105.92 per barrel. And for NGLs, it was $55.81 per barrel. Those numbers are high because over 84% of our oil production is on the Gulf Coast, which realized a significant premium over NYMEX-priced crudes in 2011. The bottom line is that for 2011, we generated an increase in net income of $54.9 million and reported GAAP net income of $172.8 million, while GAAP earnings per share increased $0.71 to $2.29 for the year. Our investors are looking to translate this into increased shareholder value. Total shareholder return, which represents the change in our stock price during the year plus dividends, was approximately 25% in a year when many E&P company stock prices were down and the S&P E&P index was flat to slightly negative. Let me also remind you that we are a dividend payer. Again, this year, we paid out a special dividend, which was the fourth time in 5 years. As a result, in 2011, the stock provided a 3.7% yield to investors. This morning, we issued a press release that stated we were doubling our regular quarterly income. We are anticipating that we will continue to increase our regular quarterly dividend going forward on a more regular basis. We're proud of these results, and our goal and our expectation for 2012 is to continue to achieve solid growth. Let me talk a little bit about our 2012 capital budget. In order to fund greater exploration and development activities, we've increased our 2012 capital budget to $425 million, excluding any potential acquisitions, which represents a 37% growth over our 2011 budget. We believe that our 2012 CapEx budget contains the right mix of projects that will expose us to large reserve targets, extended development opportunities and activities intended to sustain production cash flow. Jamie is going to outline some of these projects momentarily. Even though the budget doesn't include acquisitions, we believe it is highly probable that we will make acquisitions in 2012. We think that identifying properties with hidden value and acquiring them at attractive prices is one of our competitive advantages as it has been for nearly 3 decades. Acquisitions will allow us to continue to grow reserves in production in a meaningful way and continue to drive shareholder return. With that, I'll turn the call over to Jamie.

Thank you, Tracy. In 2011, we once again set goals for growth and profitability and our staff had executed and delivered on that strategy. Reserves, production and profits are up. We were successful in our efforts. We accomplished these results by making the right acquisitions, by operating our assets effectively to increase production, by keeping our reserve replacement cost under control, and by executing a very successful drilling program of 8 offshore and 46 onshore wells with a success rate greater than 98%. Let's talk about operational activities and first talk about Gulf of Mexico. As a significant part of our total asset base and source of cash flow, the Gulf of Mexico continues to be a focus for the company and a source of acquisitions, as well as exploration and development projects. The Fairway acquisition, along with our exploration development program in 2011, have provided us profitable opportunities, which have excellent rates of return and low funding and development cost. In 2011, we had 100% success rate in drilling our 8 offshore wells, which include 3 exploration and 5 development wells. Our offshore exploration and development programs will continue to play an important role in achieving our production and reserve goals going forward. During the fourth quarter, we successfully drilled 4 offshore wells, all located on the conventional shelf, 2 were development and 2 were exploration wells. Two of the wells were at Mahogany field, where we drilled Ship Shoal 349 A-1 exploration well and a 349 A-11 development well. These are 2 -- first 2 of the potentially 6 well drilling programs at the Mahogany field that commenced in 2011 and will continue into 2013. Both of these wells were drilled about 14,500 feet TVD, targeting oil in the P Sand, which is the main producing zone for the field. These wells are currently producing 2,115 barrels of oil per day and 7.5 million cubic feet per day gross. As you recall, we have 100% working interest in this field. The other 2 offshore wells included the South Timbalier 41 E-1 exploration well and the South Timbalier 315 A-3 development well. The South Timbalier 41 E-1 well in which we have a 40% working interest was drilled to a measured depth of 16,300 feet and found gas pay in 2 sands. The well is currently producing 2.7 million cubic feet per day and 100 barrels per day net to our interest. The South Timbalier 315 A-3 well in which we have a 50% working interest was drilled to a total measured depth of about 13,000 feet and found oil pay. The well is currently producing 170 barrels per day and 240 million cubic feet per day net to our interest. This well is part of a broader work development program for the field, with an expected increase in total production from the field of 380 barrels per day and 507 million cubic feet per day. In 2012, we plan to continue our development program at the Mahogany field, drill 5 exploration wells from the shelf and drill 2 wells in the deepwater, one of which is an exploration well. At the Ship Shoal 349 Mahogany field, we are currently drilling the A-13 well, which is expected to add 1,500 barrels of oil equivalent per day of net production in the third quarter. The 5 exploration wells in the shelf have an average working interest of approximately 56%, and the wells will be located in water depths anywhere from 33 feet to 430 feet, targeting reservoirs anywhere between 9,000 feet and 15,400 feet. The total cost of the wells to drill, complete and hook up is expected to be in the range of $50 million to $70 million net, depending on our working interest. In the deepwater, we are currently rigging up to drill the Mississippi Canyon 243 A-4 sidetrack well, which is a development well targeting an oil sand. This well is expected to produce 3,500 barrels of oil per day, net to our interest. The total estimated cost of the well is $47.6 million net. We also plan to drill a non-operated exploration well, targeting oil in the deepwater. This well is expected to spud sometime in the third quarter of 2012. We will provide more information about the well when we get closer to the actual spud date. We believe that you will be excited, as we are, about this prospect once we can fill you in on the details. Let me give you an update on the onshore activity. Currently, our focus is on both West Texas Permian Basin and on East Texas. In the Permian Basin, we have actively exploring and developing in 2 distinct areas, with approximately 30,000 net acres under lease. We will continue to evaluate potential bolt-on acquisitions to increase our lease acreage in the area. Currently, we have 3 rigs exploring and developing the 21,500 net acres we acquired in May of last year, which we referred to as our Yellow Rose Properties. Since May until the end of 2011, we drilled 29 vertical wells to total depth in the Yellow Rose Properties, of which 8 were exploration wells. In 2012, we will continue with a 3 rig drilling program to explore and develop the Yellow Rose Properties. While we expect to drill 46 development wells, we also expect to drill 6 vertical and 3 horizontal wells in this area, which should prove up additional reserves. As a reminder, our proved reserves are based on 80-acre spacing. At the end of 2011, on our Yellow Rose Properties, we had 174 drilling locations based on 80-acre spacing. At the end of 2011 -- excuse me, 80-acre spacing. At the end of 2011, our Yellow Rose Properties, we had 174 drilling locations based on 80-acre spacing that were pad location. We have another 279 drilling locations that are associated with probable reserves using 40-acre spacing. Therefore, there are 453 remaining drilling locations using 40-acre spacing. In addition, pending well results evaluation, there is a lot of additional upside available if we choose to further down space to 20 acres and/or drill additional horizontal wells, as seen by nearby operators. The cost of each vertical well to drill and complete is running around $2 million. We are targeting about 4,500 feet of vertical section in the Wolfberry. As we disclosed in our recent operational update press release, we anticipate the average vertical well will yield a 26% IRR, assuming flat pricing of $90 per barrel of oil and $3 per Mcf for natural gas, using 163,000 barrels of oil equivalent per well estimated ultimate recovery gross. The initial full month production rate is expected to be approximately 51 to 90 barrels of oil equivalent per day gross. In mid 2012, we plan to begin our pilot test horizontal program with the drilling of a horizontal well in the field. In Terry County, we successfully drilled 13 exploration wells in 2011 to test and evaluate prospects. These wells targeted the Wolfberry at a depth of about 12,000 feet, with an estimated cost of $2.3 million per well. Currently, we're at various stages in the completion and flowback of these exploration wells. Although the results are encouraging, we are still within our exploration and delineation phase. We plan to continue to analyze the data received from those wells and will most likely drill a couple of horizontal wells in the Terry County prospects prior to announcing our future development plans. We also have a large number of drilling locations in Terry County, but right now, we are focused more on the potential horizontal opportunities. It's important to realize that on this play, consisting of about 9,500 acres, we do not have any proved reserves booked related to Terry County prospects. So obviously, there's a lot of upside opportunity for reserve and production growth in 2012 and beyond. Now let's go on to the other side of Texas to East Texas other than -- which is our other focus area. In East Texas, we have 2 prospective exploration areas. One area, which we refer to as our Star Project, consists of 6 East Texas counties. And the company now controls approximately 141,700 net acres in this area that is solely focused on the James Lime. In 2011, we drilled a horizontal exploration well to test and target the James Lime formation at approximately 8,000 feet total vertical depth. The well has been completed and is currently flowing back. This well is 1 of 4 exploration wells planned to delineate the project. In 2012, we anticipate drilling 3 additional horizontal wells, which should provide sufficient data to determine future development plans. The estimated cost per well is $6.4 million with a targeted IP rate of 833 barrels of oil equivalent per day gross. Our drilling obligation for this project is approximately 3 wells per year to hold the majority of the acreage, which provides us adequate time and flexibility to explore and develop this project as we feel most appropriate. The second project area in East Texas targets both conditional and unconditional reservoirs. In 2011, we drilled and completed a vertical exploration well, targeting the Cotton Valley. We call this our Branton East Prospect and we own 35.4% working interest in it. The initial production of the well has been delayed due to higher than expected H2S content. Once this well has been fully tested, we will report the result and future plans that we may have in the area. Let's talk and give an update on the 2012 capital budget. As previously disclosed, the capital budget for 2012 is $425 million, excluding acquisitions. And this is up 37% over 2011 budget and will fund a larger exploration development drilling program. The 2012 budget currently anticipates the drilling of 10 offshore wells and 65 onshore wells, with $167 million for exploration activity and $258 million for development activity. Most all of the budget is directed to oil and liquid-type projects. It should be noted that the company has historically drilled within cash flow and most of the time has operated completely within its cash flow. As we stated in our operational press release in January, we have a reserve growth goal of at least 18% for 2012 over year end 2011 reserves of 117 million barrels of oil equivalent. In summary, we have had a very successful 2011 and we're ready to do it again in 2012. With that, I'm going to turn it over to Steve to give you an update on some other operational items.

Thanks, Jamie. We continue to seek opportunities to grow our production. In the fourth quarter, we did see some downtime due to weather-related issues but we're still able to maintain an average production rate of 49,800 barrels of oil equivalent per day. This is a 21.5% increase over the fourth quarter of 2010 and was at the high end of our fourth quarter guidance. We've said in the past that our goal in any acquisition is to take advantage of the upside and to find the overlooked potential. We continue to make progress in that respect with our activities in the fourth quarter. We've been focused on our compressor project at Main Pass 252 platform, where our Tahoe and Southeast Tahoe production flows. This project will allow us to reduce the reservoir abandonment pressure and accelerate production. In our year-end reserve report, the incremental gains due to the compressor project garnered an additional 11.3 Bcfe of reserves, net to our interest. This has been a very cost-effective reserve addition for us, with just $5.3 million net spend, which resulted in a reserve addition cost of just $0.47 per Mcfe. Another improvement for us at Tahoe was a change in the marketing of our natural gas liquids. As previously discussed, the incremental increase in the proved reserves associated with this project was approximately 2.3 million barrels of NGLs from the change in marketing strategy. In addition to the increase in our proved reserves, we expect to realize a $4.2 million annualized incremental revenue increase from the higher NGL production. As previously mentioned, we entered into an agreement with a third party that will allow them to process their production for a fee at Matterhorn. This will help us to reduce our cost when their production comes online in the back half of 2012. They will be doing the bulk of the installation of their umbilicals and flowlines and topside facilities during the second quarter. This, along with 3 other processing deals we have renegotiated, will provide incremental cash flow this year. As Jamie mentioned, our drilling program at our Ship Shoal 349 Mahogany field kicked off with the A-11, which reached TD in October. The objective P Sand was found, and the well was completed. In December, we completed the drilling of our Ship Shoal 349 A-1 using managed pressure drilling. The drilling went well, and we were able to drill the well under the time frame we anticipated and we're $1.5 million under budget. These wells are producing 2,150 barrels and 7.5 million cubic feet per day gross. We are currently drilling the A-13 well, which is a development well up-structure to an existing well to further develop the P Sand. Mahogany, our largest offshore development, is mostly oil, and when the work is complete, should provide a nice production boost. At Main Pass 108, we finished the installation of the #8 caisson and pipeline and the well is online, producing 6 million cubic feet per day, along with 140 barrels per day gross. We continue to assess the prospectivity of this area and expect to have a rig back in the Main Pass area at the end of this year or next year. Our recompletion and workover program for 2011 was again a success as we performed 31 recompletes and 35 workovers offshore that added net initial incremental production of approximately 98.5 million cubic feet equivalent per day at a cost of less than $40 million. As we move into 2012, we have numerous projects on the horizon, including work at our Virgo platform. Regarding our onshore operations, at our Yellow Rose Properties in the Permian Basin, we continued with our 3 rig drilling program throughout the fourth quarter and reached TD on 13 wells. We continue to assess ways to optimize profitability in the field, including reducing well spacing from 80 acres to 40 acres, evaluating the drilling of horizontal wells and implementing new frac techniques. Additionally, the installation of remote control systems to monitor each well's lift system is in progress. Our previous issues regarding gas pipeline constraints have been addressed, and we do not foresee this continuing to be a problem in 2012. Let me move on to production guidance. For the full year of 2012, we anticipate our oil production to be between 5.9 million and 6.6 million barrels, our natural gas liquids production to be between 2 million and 2.3 million barrels and our natural gas production to be between 54 and 60 Bcf, for a total production for the year to be between 16.9 and 18.8 million barrels of oil equivalent or 101.1 and 112.9 Bcfe. This guidance does include some downtime for hurricanes similar to what we experienced in 2011. On LOE, our guidance for LOE for 2012 is between $215 million and $237 million. Overall, lease operating expenses on a per Boe basis is expected to be flat or slightly lower due to higher production volumes partially offset by increased cost associated with the full year of operations in 2012 from the properties we acquired in 2011. Our guidance for gathering, transportation and production taxes for 2012 is between $25 million and $35 million. Production taxes are expected to be higher in 2012 compared to 2011, with increased production in Texas and Alabama. Now let me turn it over to Danny to discuss fourth quarter results.

Thank you, Steve. Revenues for the fourth quarter were $261.9 million. That's up $74.9 million from fourth quarter last year due to higher oil and NGL prices and higher production volumes. Just like in the third quarter, we greatly benefited from higher oil prices, which when coupled with higher production volumes led to higher earnings. Crude prices averaged over $112 per barrel during the fourth quarter of this year, compared to $84.04 per barrel in the fourth quarter last year. Although the Brent and WTI differentials narrowed in the fourth quarter following the announcement of the Seaway pipeline with reverse flow and it began bringing Mid-Continent barrels to the Gulf coast, NYMEX-priced WTI prices rose as a result of -- and the prices remained strong. Thus far, in 2012, the differential was widened again and recently, Brent has widened upwards to $19 per barrel of WTI. Accordingly, we are seeing excellent pricing on our Gulf Coast barrels. 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 1.6 million barrels, our NGL production was nearly 613,000 barrels, and our natural gas production was 14.4 Bcf. On an oil equivalent basis, production was 49,800 barrels per day, and that's up from 41,000 barrels per day in the fourth quarter last year and is up 3.8%, sequentially. Let me move on to a discussion of expenses. For the fourth quarter, lease operating expense or LOE was $59.3 million, compared to $47.5 million in the fourth quarter of last year. Although LOE on a per barrel basis increased 2.9%, our production on a barrel of oil equivalent basis increased 21.5% and our revenues increased over 40%. Our base LOE was up $5.4 million principally because of the Permian Basin and Fairway field additions. The facilities portion of LOE increased $3 million with the work at our Yellowhammer plant acquired with the Fairway properties and various offshore projects. Insurance premiums, which are also a component of LOE, are up due to substantial expanded coverage and our recent acquisitions both onshore and offshore. Our depreciation, depletion and amortization rate for the fourth quarter decreased to $18.95 per barrel from $19.50 per barrel in the fourth quarter of last year due to the substantial increase in our proved reserves. On a nominal basis, DD&A was $86.9 million, an increase of $13.3 million over the fourth quarter of 2010 due to higher production volumes. General and administrative expenses were $20.1 million in the quarter, which is up $4.9 million over the fourth quarter of last year. For the year, G&A increased to $74.3 million from $53.3 million for 2010, primarily due to higher incentive compensation as a result of improved financial and operational performance and expanded activities onshore and offshore. G&A was also higher due to costs associated with acquisition activities, surety premiums, transition services paid to the sellers of the acquired properties, and litigation settlements and accruals. Furthermore, we earned administrative transition service fees in 2010 related to an asset disposition that did not reoccur in 2011. On a per barrel basis, G&A was $4.39 per barrel for 2011. That's up 20% from the $3.67 per barrel for 2010. Our guidance for G&A expenses for the year 2012 is between $75 million and $85 million. And on a per barrel basis, G&A is expected to be flat to slightly higher due to an expected increase in production volumes, partially offset by higher cost associated with the full year of operations in 2012 from properties acquired in 2011. As you've already heard, we have another really solid quarter operationally that translated into good -- really good financial results. For the quarter, net income, excluding special items, was $51.5 million or $0.69 a share compared to $29.6 million or $0.40 a share in the fourth quarter of last year. The fourth quarter also topped the third quarter when we reported $42.4 million of net income, excluding special items of $0.56 per share. Let me repeat that, the fourth quarter was better than the third quarter when we reported $42 million of net income, excluding special items and $0.56 a share. Also, keep in mind that our effective tax rate for the fourth quarter of 2011 was 33% compared to 16.8% in last year's fourth quarter with the reversal of the valuation allowance that we did throughout 2010. The special items that I referred to are explained in our fourth quarter earnings release. Year-to-date adjusted EBITDA is over $646 million and that's up over $196 million or 44% from what we reported in 2010. It is better -- a substantially better financial performance. Net cash provided by operating activities for the year was $521.5 million, compared to $464.8 million for 2010. As a reminder, we received a tax refund from the United States Treasury of almost $100 million in 2010 and we paid out over $35 million in taxes during 2011. Otherwise, cash flow from operating activities is up over $192 million, with the higher production volumes and higher realized sales prices. Also, keep in mind that, that cash provided by operating activities is reduced by plug and abandonment expenditures. For 2011, such expenditures were $60 million, and insurance reimbursements related to P&A work was $21 million, resulting in net out-of-pocket of $39 million. Our net out-of-pocket for 2010 for such activity was $33 million. We expect to make additional recoveries from our insurance carriers in the future as we perform plug and abandonment work on facilities and platforms that were damaged during Hurricane Ike. Our cash balances as of February 23, yesterday, was $26 million and we had $76 million drawn under the revolver. Our borrowing base revolver capacity is currently $575 million. So our liquidity continues to be strong, which will allow us to continue to pursue the growing list of acquisition opportunities, both offshore and onshore. For 2011, our effective tax rate was 34.6%, with 70% deferred and the rest, current. We paid in $16 million of federal income taxes during 2011 related to the 2011 tax year, and we'll pay an additional $10 million on March 15. 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, as I said earlier, when we were able to completely reverse the previously established valuation allowance which reduced tax expense throughout 2010. For 2012, our effective tax rate is expected to be in excess of 35% due to a combination of federal statutory rate, state taxes related to our West Texas production and Alabama state taxes due to our Fairway production. We anticipate that 88% will be deferred and the rest will be current. Finally, during the fourth quarter of 2011 and that's more to the first quarter of 2012, we've added oil swaps priced off of Brent oil -- off of Brent oil for our production of oil in 2012, 2013 and 2014. A summary of our commodity derivative positions can be found at our Investor Relations section of our website. And with that, I'll turn the call back over to Tracy Krohn. Tracy?

Thanks, Danny. Well, it was an active fourth quarter and it was a very active 2011. And we're expecting even more activity in 2012. We anticipate that the mix of exploration and development projects both onshore and offshore in our 2012 plan, combined with the acquisition opportunities we expect to see in the market this year, has the potential to generate substantial growth for W&T. Our goal for reserve growth is at least 18%. And although we provided production guidance with any potential acquisitions, you could expect our production growth in 2012 to exceed such guidance. We believe we're a preferred buyer in the Gulf of Mexico, with over 28 years of proven experience for safe operations. And now, we're recognized as an onshore buyer and operator as well. We're proud of our results in 2011, and we look forward to a stronger performance in 2012. This company is continuing to evolve and grow, and our numbers certainly show it. We also believe that we're accomplishing this in the proper manner by drilling within cash flow. And that by doing so, we're able to maintain good liquidity to take advantage of opportunities and acquisitions in exploration. With that, we're glad to take your questions. Operator, if you would please open the phone lines for Q&A.

[Operator Instructions] And our first question is from the line of Biju Perincheril.

Jefferies. Tracy, a couple of questions. First, on the East Texas Cotton Valley well, you mentioned there is some H2S presence there. Can you talk about how much and what's the solution there and the timing of that?

Sure. The Cotton Valley well you're talking about has pretty high H2S content.

Yes, and what -- I was wondering if you could quantify what high is?

Well, we're not exactly sure because we don't have an accurate test, but I'm going to tell you it's probably at least 20%. That's kind of the consensus. We're preparing the well for another test. We're going to have to get a different tree. It's pretty high pressure, so we need a tree trim for higher H2S content. And we just want to be very careful and do this methodically and make sure that we do it right. We've got a lot of -- we think we've got a lot of reserves there and we're going to make sure we get good test. It's going to take us a little while to get the tree. Steve, what is our current timing on this tree?

Actually, the timing on the tree is about half a year, but we should be able to actually flow test it and then figure out what facilities we need to modify, as well as the tree.

Okay. And then other than the tree, do you need special metallurgy for any of the other equipment, the downhole equipment, things like that or -- because of the high H2S?

Everything downhole was designed for high H2S. We will have to modify some of the facilities dependent on how high the H2S is.

Okay. And then as far as removing H2S, can this be sort of a simple, I mean, do you need -- or don't you need something more elaborate than then to kill the concentration?

Actually, right now, the pipeline company is allowing us to flow to them at a certain rate. And if we go over that rate, yes, we would actually have to install some additional facilities.

Okay. And then the other East Texas project, the James Lime project, you mentioned 833 Boes a day, is that the actual test rate? Or is that what you're sort of anticipating?

That's the expectation.

Okay. And how do you think about the oil, gas, NGL mix there?

We don't really have an answer for that yet. Again, we haven't put a proper flow test on the well primarily because the H2S content caught us out a little bit. So we'll get a test on it as soon as we can, but this is a very high rate gas well.

All right. I was talking about the James Lime area.

Oh, I'm sorry, excuse me. James Lime, yes, it is high liquids. We're still testing that well. We're getting ready to drill another one.

Okay. And in Q2, are there other objectives that are prospective there, like the pad? Or are you planning to test any of those other zones?

That's not our current plan.

Okay. And then on the production numbers, I think I missed it, if you mentioned it, does it include any wedge for acquisitions? Or is it only from drilling?

No. There is no wedge in there for acquisitions at all. Any acquisitions would almost certainly carry us up over our current guidance.

Okay. And one other question. The horizontal well in Perry County that you're planning on, is that -- can you talk about the target objective there?

That's Wolfberry.

Okay. So it will be the Wolfcamp section that you'll be going horizontal in?

Yes.

[Operator Instructions] And our next question is from the line of Dan McSpirit.

BMO Capital Markets. I was wondering if you could share your thoughts on pricing for the balance of this year, just in general terms at least, what you expect in terms of price realization. I ask that question in light of the potential reversal of -- or the contemplated reversal of the Seaway pipeline which may or may not narrow the spread on WTI versus Brent?

Dan, if I knew what prices were going to do, I'd pass it to something else, buddy. I don't know what prices are going to do. I don't know what world politics are going to do. I just don't. I can't prognosticate on that, but I appreciate the question.

Okay, fair enough. And any guidance here going forward, whether 2012 or beyond, on asset retirement obligations, that expense? I ask that as more capital is allocated to onshore activities and with it, greater drilling activity may be away from the Gulf of Mexico.

Yes, I think that's a fair question. ARO is something we are mindful of all the time. We do have ongoing obligations in the Gulf of Mexico. I'm with those who've been pretty adequately spelled out in all of the -- all the documents that we have right now. I would expect that it will stay on schedule. Oddly enough, as a result of some of the slowdown in the Gulf of Mexico, it's deferred some of our obligations just waiting on permits.

Okay, got it, understand. And then lastly for me. Forgive me if you covered this already, but the timing of the additional horizontals to the James Lime at your Star Project this year?

We're starting on the next well, literally building the pad as we speak. We'll probably drill at least 2 wells this year. Steve, I know you've said 3 so -- I said 2, but probably 3.

Okay, yes.

Okay. And the timing of those results, late first half 2012 then? Early 2012?

We'll have more results probably in the second half, yes.

[Operator Instructions] And our next question is from the line of Noel Parks.

It's Ladenburg Thalmann. I just had a couple of things. There was a mention earlier about a non-operated deepwater prospect that I think you said you need to spud again starting in the third quarter? I was just curious, is that something that was identified from your long-existing inventory? Or is that a prospect that you found a change here more recently?

Actually, we intended to drill that well last year. So it is deferred from existing inventory. Of course, it's an exploratory well. But yes, this has been deferred somewhat primarily due to permitting and rig conditions.

Sure. And is there going to be significant capital at -- or I should say that the 2012 budget include much capital for that? Or is most of that are hidden in 2013?

No, that's included in our budget for 2012.

Okay, great. And just a more sort of general question about your outlook on acquisition. Is it safe to assume that at this stage, you're perhaps even more concentrated on getting acquisitions done, in terms of just your prospect list being larger than it may have been in the past?

I'm not quite sure I understand the question, Noel.

Oh, sorry. I just meant -- I'm just picking up what sounds to me more focused than perhaps ever before at a time the company naturally having a list of properties that you are very actively looking at and very closely examining for acquisition. [indiscernible] being sorted in the market, but it sounds like that's really an intensified focus this year?

Well, it's not just -- it's never more of a focus one year than the other. I mean, the reality is that right now, there's a lot of people selling assets and part of that because of changes in their balance sheet. So we're just -- we're looking at a lot of different properties, onshore and offshore. And of course, we've diversified a bit more onshore. So we are seeing more opportunities onshore as well.

Our next question is from the line of Steve Berman.

Pritchard Capital. A couple of things. Tracy, with the Davy Jones on the verge of flow test results here. The first kind of ultradeep results were getting up. Does W&T have any prospective acreage for the ultradeep? And if so, do you -- can you foresee yourself putting any capital towards that in the next couple of years?

Yes and yes. We want to wish McMoRan and Plains and EXXI, all those guys, very good luck in their upcoming flow tests. We've been anticipating it very eagerly. I hope they have a rousing success. We think it certainly enhances our corporate profile.

This concludes the question and answer session. I would now like to turn the call back to Mr. Krohn for any closing remarks. Please go ahead.

Thank you very much everyone. We'll talk to you next quarter.

Ladies and gentlemen, this concludes the W&T Offshore's Fourth Quarter Earnings Conference Call. You may now disconnect.