W&T Offshore Inc (WTI) 2011 Q1 法說會逐字稿

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

This conference is being recorded today, Tuesday, April 26, 2011. I would now like to turn the conference over to Janet Yang, Finance Manager of 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 for the first 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 May 3, 2011. To use the replay feature, call 303-590-3030 and dial the passcode 4434719 pound.

Information recorded on this call speaks only as of today, April 26, 2011, and therefore, time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our first-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, Janet. Good morning, everyone. We appreciate you joining us for our first-quarter 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. Other members of management are here for the Q&A session that will follow our prepared remarks.

Well, good news, yesterday we announced that we had entered into a purchase and sale agreement with private sellers to acquire approximately 21,900 gross lease hold acres -- that's 21,500 net acres -- in the west Texas Permian Basin for a purchase price of $366 million. Now that is subject to adjustments and an effective date of January 1, 2011. Estimates of proved reserves to be acquired are approximately 27 million barrel equivalent or 164 Bcfe equivalent, and 53 million barrels equivalent of proved and probable reserves, 318 BCF equivalent using a 6 to 1 MCF barrel equivalency. And that's all at December 31, 2010.

That's about 91% oil and natural gas liquids. The current wells produce around 2,800 barrel equivalents per day. This is a transformative acquisition for us. As we told you last call, although the Company's focus has historically been offshore, we have repeatedly stated that we have been out here looking around in different areas and other basins including onshore, and as well internationally.

Our lack of investment onshore or otherwise was not a philosophical issue, but rather a rate of return issue. We believe that acquiring and operating these Permian Basin oil properties is a transformational move for us, and that these properties will make a solid contribution to the Company's future.

I would also like to point out that Main Pass 108 field is back online again and doing very well. Steve will have more info on that shortly.

We had another great quarter highlighted by a full quarter of operations of the 3 deep-water properties acquired from Shell in November 2010, and also strong operating results bolstered by high production volumes and rising oil prices. Our production was above the high side of guidance, while expenses were generally below the midpoint of guidance. Production for the quarter was 48% oil and liquids, which benefits us in such a strong crude oil price environment.

The realized price in our oil sales also reflects the premium over WTI that we started seeing in February and continued through March, and even thus far in the second quarter. As you may have seen this discussed in numerous publications, the premium over WTI appears to be due to the surplus of crude at Cushing, and that the crudes on the Gulf Coast better reflect world market conditions. So, we are getting several dollars per barrel premium on those crudes in the Gulf Coast.

Regardless, earnings excluding special items came in above analyst estimates. GAAP earnings were $0.25 per share, and excluding special items, adjusted earnings per share was $0.43, compared to first-call consensus of $0.31 per share. Our liquidity continues to be strong and getting stronger, and our revolver is undrawn and available.

Let's talk a little bit about our 2011 capital budget, excluding acquisitions. As we discussed in our last call, our 2011 cash capital expenditure budget was $310 million, and excluded any amounts that we might spend on acquisitions. Again, that doesn't include acquisitions. The announced budget included 14 gross wells, and we have drilled 3 wells thus far, and all have been successful. Those were 3 exploratory wells that were successful, so we are evaluating additional wells to be drilled in 2011, and Jamie is going to discuss that in much more detail.

Capital expenditures associated with planned development activities for the Permian Basin properties for the rest of 2011 are currently estimated at $35 million to $40 million. Because of changes in the types of wells to be drilled, along with changes in activities that we had planned this year, our capital budget now has sufficient room to accommodate the development plan for the new Permian Basin properties. That means we will continue to drill, within clash flow and cash on hand.

So, we're obviously off to a great start and another acquisition of more wells in 2011. Now I'm going to turn it over to Jamie to further explain our acquisitions, drilling program, and budget, so stick around. Jamie and Steve have even more good news for you. Jamie?

Thank you, Tracy. Coming into 2011, our primary goal was to increase the Company's production and reserves with profitable projects. Our strategy to achieve this goal was to pursue acquisitions and drilling opportunities in area with production and upside to support growth year-after-year. Our current focus areas include the offshore Gulf of Mexico, onshore Gulf Coast, and West Texas Permian Basin. We would expand these focus areas with projects that have good cash flow and rates of return using full-cycle economics.

First, I'd like to give you some details about our West Texas Permian Basin property acquisition. As Tracy mentioned, we have entered into an agreement to acquire production and acreage in West Texas Permian Basin. This acquisition contains 70 producing wells with about 21,900 gross acres, 21,500 net acres, the proved reserves of around 27 million barrels equivalent, and 2P reserves are 53 million barrels equivalent, which are over 91% oil and liquids, and provide significant upside opportunities.

The current wells produce about 2,800 barrels equivalent per day. Since the effective date of January 1 of this proposed acquisition, production has increased from about 1,900 barrels equivalent per day. There are 3 active drilling rigs in the field, and ongoing completions are being made on the new wells. The acquisitions provide hundreds of proved, undeveloped, and probable well locations in the 22,000-acre development, most of which are 100% working interest. We expect to keep at least 3 rigs working in the field throughout the remainder of 2011 and beyond. Accordingly, we would expect daily production to increase. We will update you more at closing and in future calls.

Next, let's discuss the Shell transaction. If you recall, we entered into a letter of intent with Shell to acquire a fourth property. That property is comprised of a 64.3% working interest located in the Gulf of Mexico shelf, and related ownership interest in a gas treatment plant. This transaction should close during the second quarter. The average daily production in March was 21.6 million cubic feet per day equivalent, which is comprised of gas and condensate. This production is not included in our guidance. Again, is not included in our guidance.

Let me share some more good news as I describe our drilling and leasing activities. During the fourth quarter, we commenced drilling 3 exploratory wells. One well, located in offshore, Main Pass 180, and 2 other wells located onshore Texas, all of which were successful. In regards to the offshore well, the Main Pass 180 A2 well, in which we own 100% working interest, reached total depth of 13,950 feet in the middle of February. And we found 91 feet of net vertical pay of high quality gas sands in 3 separate zones.

Obviously, this is a nice discovery for us. This well is now online, and is currently producing 11 million cubic feet equivalent per day. After the completion of this well, the rig moved to a development well. That would be the Main Pass 108 D3 sidetrack, charging known field pay sands. We have now reached TD of that well, and we will be logging pay zones in the next few days.

Once the D3 side track well is completed, we expect to keep the rig in the field to drill 2 additional development wells. We like this Main Pass 108 field area, as it has high-yield condensate along with gas production.

In regards to the successful onshore wells, 1 well is located in east Texas and 1 well is located in south Texas. Both are non-operated wells. We have a 25% working interest in the east Texas well, which has recently reached total depth. The east Texas well appears to be a significant discovery, finding both conventional and unconventional reservoirs. We are currently running pipe to complete the well, and expect to have production online in the third or early fourth quarter.

The second onshore well is located in south Texas. We have a 50% working interest in this discovery. The well has been completed, and found 22 feet of gas and condensate. The producing well is currently waiting on additional fracturing to stimulate production. Also, keep in mind there are development opportunities around both of these areas.

An additional onshore exploratory well, located in south Texas, that is expected to spud around May 1. Our working interest in that well will be 50%, and it will test a conventional reservoir. It is a good-looking prospect with several offset development wells, if the exploration well is successful.

In regards to our other onshore exploration activity, we have acquired seismic and -- since last year, we have been leasing within several exploratory prospect areas located in West Texas Permian Basin, some of which are operated and some of which are non-operated. To date, we have acquired approximately 9,400 net acres, and expect to drill numerous exploratory wells in 2011.

We expect to drill in 2 prospect areas. One area, there are 4 non-operated wells scheduled. W&T would have about a 32.5% working interest. And in another area, we have an additional 3 operated wells with about 80% working interest.

We will kick off the these drilling programs in the second and third quarters, and with success, we will have a continuous drilling program for years to come. These wells are in addition to the drilling program associated with the new acquisition. West Texas Permian Basin is clearly an area of focus for W&T, with now over 30,000 net acres. And our recent acquisition announcement complements and supports our exploration projects in our new area of growth.

The capital budget for 2011 is $310 million, which initially included 14 wells located offshore and onshore. For the first quarter, our capital expenditures were $39.9 million, which included $14.6 million for exploration, $21 million for development, and $4.3 million for seismic, leasehold, and other costs. Remember, the capital budget didn't include any capital for acquisitions.

With the slowed permitting process with the DOE [MRE], has caused some of our budgeted wells to move later in the drilling schedule. Consequently, it has freed up additional drilling dollars that can be allocated to other projects in 2011. It should be noted that W&T does not lose or jeopardize any leasehold rights as a result of these deferred wells. We expect to use these dollars to drill additional wells in west Texas or Gulf of Mexico shelf prospects in our drilling inventory with the emphasis on oil.

At present, the $310 million budget, W&T now expects to drill about 36 wells, including the wells with the new acquisition in 2011. We expect to drill 14 or more exploration wells, both offshore and onshore. Three exploration Wells have already been drilled. Additionally, we expect to drill a deep shelf Gulf of Mexico well at [West Town 73] with about 30% working interest; a deep water Gulf of Mexico well, to spud in the fourth quarter, in which we expect to have a 20% working interest; an exploration well, scheduled for ship shoal 349, that would be our Mahogany field, which we own a 100% working interest; 7 or more exploration wells onshore West Texas Permian Basin; and 1 exploratory well South Texas onshore.

On the development side, we expect to drill about 22 wells, which includes 3 development wells in the offshore Gulf of Mexico Main Pass 108 field; 1 development well in our offshore Gulf of Mexico South Timbalier field; and 1 development well in our offshore Gulf of Mexico Ship Shoal 349 Mahogany field; and 15 to 20 development wells in the West Texas Permian Basin and South Texas field. Again, we expect to drill about 36 wells, which includes the wells in our new acquisition, with our $310 million budget.

Besides drilling, other planned activity for this year includes well completion, facility projects, numerous recompletes, acquiring additional leasehold, and obtaining more seismic, both onshore and offshore to support our exploration program. As we said in the last call, we are actively evaluating drilling and acquisition opportunities, both onshore and offshore. Our current activity fully substantiates that statement.

With our focus on growth, these additional onshore projects complement our robust Gulf of Mexico portfolio, adding reserves and increasing our daily oil production for years to come.

With that, I'd like to turn it over to Steve Schroeder to update you on our operations.

Thanks, Jamie. I am pleased to report the Main Pass 108 field was restored to production on March 31. As you may recall, the field has been shut in since June of 2010, due to issues with third-party pipeline. The production has now been rerouted and is connected to a different pipeline that provides us better flow assurance and better pricing.

We also brought online the Main Pass 98 development, which includes the Main Pass 98 A1 and the Main Pass 180 A2 wells. Combined, the 2 wells are producing approximately 800 barrels of oil per day and 12 million cubic feet per day, net. Once these 2 wells have been brought on to full rate, we will begin producing the Main Pass 108 E3 well. Current production from the Main Pass 108 area is approximately 1,400 barrels of oil per day, and 38 million cubic feet per day, net, or 46 million cubic feet equivalent per day. We expect the rate to increase another 8 million to 10 million cubic feet equivalent per day, when the Main Pass 108 E3 well comes online.

As Jamie stated, additional development of this field includes the well we are currently logging, which is the Main Pass 108 D3 side track. After the D3 side track has been logged and completed, we plan to mobilize the rig to an open water location to drill an additional development well. Currently, permits have been submitted for this well and are awaiting approval.

At our Ship Shoal 299 field, the pipeline that services the field was shut in last December due to paraffin buildup. During the quarter, we were able to obtain permits, allowing us to clean out the paraffin plug with coiled tubing. The operation was a success, and we brought the field back online nearly a month ahead of schedule, and under projected cost.

During the first quarter, we performed 9 recompletes and 15 workovers that added net incremental production of approximately 12.5 million cubic feet equivalent per day, at a cost of about $13 million. Included in this work, were 4 successful jobs at Virgo, where we have increased production from 7.4 million cubic feet equivalent per day gross, to 14.7 million cubic feet equivalent per day gross, or nearly double.

Also, at Matterhorn, we did a workover on the A-5 well, and brought the well back online at approximately 200 barrels of oil per day, and 100,000 cubic feet per day net, which had been shut in for 3.5 years. Later in 2011, we plan on mobilizing a jack up rig to a West Delta 30 field for a full well recomplete program, and a platform rig to South Timbalier field for a 2-well program. Both of these programs will focus on work to develop oil reserves.

Last quarter, we discussed the permitting process. It is improving daily, and there have been a number of deep water permits issued, most of which are allowing the operator to return to wells that were in progress before the Macondo blowout. The shelf permits are also moving along, and as you know, we received all the permits approvals to lay a new pipeline and get the Main Pass 108 field back online, and have maintained a continuous operation with 1 rig over the last year.

Relative to deep water operations, W&T Offshore joined the Helix Well Containment Group in March. The Helix Well Containment Group is a consortium of 24 deep water operators in the Gulf of Mexico that have come together with the common goal of expanding capabilities to quickly and comprehensively respond to an incident to protect employees, the environment, and communities. The Helix Well Containment Group, another similar consortium, and the Bureau of Ocean Energy Management are working together, formulating plans to develop deep water oil and gas leases in a safe and environmentally prudent manner.

Let me update you on production. First-quarter production exceeded guidance because of the Ship Shoal 299 repairs were a month ahead of schedule, and better than expected well performance. For the second quarter, we anticipate our oil and natural gas liquids production to be between 1.6 million and 1.8 million barrels, and our natural gas production to be between 13.6 and 15 BCF, and our total production to be in the range of 23.2 BCFE to 25.6 BCFE. Production guidance includes the planned buildup from our capital budget, and the pending Permian Basin acquisition, but does not include any production associated with the shelf property to be acquired from Shell.

Production for the second quarter will benefit from the Ship Shoal 300 and Main Pass 108 fields returning to production, along with the buildup from our successful Main Pass 98, Main Pass 108, and Main Pass 180 exploration wells. However, we will experience about a month of downtime at Matterhorn. During the second quarter, we will be repairing and upgrading the facilities, as well as refurbishing the tendon tension monitoring system. The repairs to the tendon tension monitoring system were identified when we purchased the field, and we should be mobilizing soon to take advantage of good diving whether. We expect all repairs to be completed by the end of the second quarter. Matterhorn had been producing around 24 million cubic feet equivalent per day net, and this anticipated downtime is included in our production guidance.

For all of 2011, we anticipate our oil and natural gas liquids production to be between 6.4 million and 7.4 million barrels, and our natural gas production to be between 48.8 and 58.6 BCF, and for the total production for the year to be between 87 and 101.1 BCFE, or approximately a 4 BCFE increase in our annual guidance.

Lease operating expenses in the first quarter were within guidance. Our guidance for the lease operating expenses for the second quarter of 2011 is between $54 million and $59 million, and for the year, our guidance has changed $2 million and is now expected to be between $190 million and $220 million. These estimates do not include any allowance for hurricane-related expenses, or insurance reimbursements.

As you can tell from the LOE guidance for the second quarter, we will be expecting LOE to be higher due to increased facility expenditures, primarily at Matterhorn, and our sandblasting and painting programs, and due to increased workover activity, which is expected to increase production for future months. Our guidance for gathering, transportation, and production taxes for the second quarter of 2011 is between $6 million and $9 million, and for the year between $25 million and $28 million.

Now, let me turn it over to Danny to discuss our first-quarter results. Danny?

Thank you, Steve. Revenues for the first quarter were $210.9 million, and that's up considerably from $169.6 million in the first quarter last year. That's due to higher oil prices and higher volumes. And it is up from $187 million in the fourth quarter of 2010 due to higher prices.

Our average realized sales price for oil and natural gas liquids was $88.43 per barrel in the first quarter. That's up considerably from $69.95 per barrel in the first quarter last year, and $77.27 per barrel in the fourth quarter last year. The average realized sales price for natural gas is $4.29 per MCF in the first quarter. That's down from $5.38 per MCF a year ago, but up from $4.01 per MCF sequentially.

Production in the first quarter was 22.7 BCFE, and that's compared to 20.0 BCFE in the first quarter last year, and 22.6 BCF sequentially. Volumes are up with the contribution of the new Shell production volumes beginning in November 2010, and would have been even higher if not for the production shut in of our Main Pass 108 field, due to the pipeline outage that started in early June of last year.

Let me move on to expenses. Starting with LOE, LOE is made up of 5 components -- base LOE, insurance premiums, workovers, facilities work, and hurricane remediation. In the first quarter of 2011, LOE increased to $52.4 million, or $2.31 per MCFE, from $35.4 million, or $1.77 per MCFE in the first quarter of 2010. On a component basis, base LOE decreased to $1.71 per MCFE, from $1.72 per MCFE in the first quarter of 2010, and workover expenses decreased to $0.29 per MCFE, from $0.35 per MCFE in the first quarter of 2010.

As an offset, facilities costs per MCFE increased to $0.26, and that's compared to only $0.01 per MCFE in the first quarter of 2010, and hurricane remediation net of insurance was $0.05 per MCFE in the first quarter of 2011, but that is compared to a reduction or a credit to expense in the first quarter of 2010 of a negative $0.32 per MCFE. Facilities expenses were up due to the pipeline repairs at our Ship Shoal 300 field to remove paraffin and work on the newly acquired deep water properties.

Finally, we incurred hurricane remediation costs in the first quarter of 2011, while the first quarter of 2010 was a net reduction for insurance reimbursements and the reversal of previously recorded hurricane remediation accruals. Based on our production and LOE guidance for the year, our LOE per MCFE is expected to decrease from that reported in the first quarter of 2011. DD&A on an MCFE basis is down to $3.26 per MCFE in the first quarter, compared to $3.47 per MCFE in last year's first quarter, due to an increase in proved reserves. On a nominal basis, DD&A is up $74 million for the quarter, and is higher than last year's due to higher production.

General administrative expenses were $18.1 million in the first quarter this year, which is up from $10.4 million in the first quarter last year, and $15.1 million sequentially. The increase in G&A is primarily due to higher incentive compensation, surety bond premiums, and service fees attributable to the properties purchased from Shell.

No amounts for incentive compensation were paid in the first quarter of 2010. But during 2010, we implemented a new incentive compensation plan. Part of the incentive compensation amount in 2011 is related to grants made in 2010 that are amortized to compensation expense over the service period, while the other part is due to anticipated achievement of Company performance relative to targets. Our guidance for G&A expenses for the second quarter of 2011 is between $20 million and $22 million, and for the year between $69 million and $80 million.

Let's talk about financial performance. For the first quarter of 2011, we reported net income of $18.6 million or $0.25 a share, that compares to net income of $42.3 million or $0.57 per share reported in last year's first quarter. Adjusted to exclude special items for the same periods, net income was $32.7 million, or $0.43 a share in the first quarter of 2011, compared to $39 million or $0.52 a share in the first-quarter last year, and $29.6 million or $0.40 per share sequentially. Keep in mind that our effective tax rate this year is 35.3%, and last year was only 8.7% with the reversal of the valuation allowance throughout 2010. The special items are explained in today's earning release.

Adjusted EBITDA was $133.3 million, and that's compared to $119.8 million in last year's first quarter. Net cash provided by operating activities for the first quarter of 2011 was $72.7 million, and that compares to $87 million in last year's first quarter. The decrease in cash flow was primarily as a result of an increase in tax payments, and ARO expenditures.

Moving on to cash, our cash balance at March 31 was $58.4 million, and that is an increase from a year-end balance of $28.7 million, but our cash balance is currently in the $140 million range. Similar to year end, no amounts were outstanding on the revolver at the end of the quarter. Our revolver and borrowing base was $405 million at the end of the quarter. We are currently in the process of entering into a new 4-year revolving bank credit facility, and expect the new borrowing base to be $525 million. That amount is expected to increase automatically to $575 million when we close on the next shelf property from Shell. Our liquidity continues to be strong and allow us to continue to grow the Company.

Now moving on to ARO, expenditures for asset retirement obligations were $17.5 million in the first quarter, that's $17.5 million, and insurance reimbursements related to P&A work was $8.1 million. We expect to make additional recoveries in the future as we perform (inaudible) on facilities and platforms that were damaged during Hurricane Ike.

Moving on to taxes. From federal income taxes, as I mentioned earlier, our effective tax rate is up considerably from last year when we were able to completely reverse the previously established valuation allowance, which reduced tax expense throughout 2010. As a result of reversing the valuation allowance and utilizing the deduction attributable to qualified domestic production activities under section 199 of the Internal Revenue Code, our effective tax rate for the first quarter of 2010 was 8.7%. For 2011, our effective tax rate will be in the range of 35% to 36%, virtually all of which will be deferred, except for an amount related to alternative minimum tax, which will require a small cash payment.

Finally, on hedges, no changes were made during the first quarter to our hedging positions, which are all oil-related. A hedge schedule with curb positions can be found within our Form 10K. As oil prices continue to rise, our derivative loss continues to increase as well. Fortunately, only a small portion of our oil production is currently hedged, but with the run-up on oil prices, the loss of $23.8 million for the quarter is quite the contrast to the $5.9 million derivative gain that we reported last year's first quarter. Obviously, we are still benefiting greatly from the high oil prices.

With that, I will turn the call back over to Tracy for closing remarks.

Thanks, Danny. Okay, so we are increasing reserves and production. What does that mean? Well, that means growth. The market has inquired a great deal about growth, we've always insisted that we have cash flow and earnings associated with that more predictable growth.

We've historically focused on the Gulf of Mexico because it has provided a great rate of return, but we also had an objective to be in other basins where we would make positive, full-cycle economic returns. The acquisition of the Permian Basin properties during the second quarter will allow us to continue on with our goals, and continued emphasis on growth through acquisition and drilling.

We will see increased production immediately via the acquisition of producing properties, increasing production through drilling over time, and an expanding reserve base. In other words, more predictable growth. The acquisitions completed in 2010 helped us get back to growing reserves, production, and cash flow. And the acquisition in the Permian Basin will expand on that as well.

In addition, bringing on oil production in this oil price environment will sure help the bottom line, too. Please keep in mind that we will continue to look for assets to add to the W&T portfolio. We believe that there are many more attractive acquisition opportunities for us out there, both onshore and offshore. In addition, we think our capital budget provides us exploration and development drilling opportunities, both onshore and offshore, with an emphasis on oil projects.

As Danny mentioned, our revolver is in the process of being extended out another 4 years, and our borrowing base is expected to increase to $525 million from the current $405 million. The amount is expected to automatically increase to $575 million, when we close on the shelf property being acquired from Shell. Also bear in mind that these borrowing base amounts were determined before considering the Permian Basin oil properties. These properties will clearly help the borrowing base as well. The new revolver will put us in a very strong liquidity position and support our ongoing needs.

As we think about the remainder of 2011, we continue to evaluate the acquisition and drilling opportunities that continue to present themselves, and we will continue to do the things that increase shareholder value. When you combine the Permian Basin acquisition with the other 9,700 net acres that we already own in West Texas, we now have an additional focus area with about 30,000 net acres, which complements our Gulf of Mexico portfolio. We will also be extremely diligent in bringing the West Texas properties into the W&T portfolio. We have a lot of work ahead of us; it's all pretty good news.

And we will be glad to take your questions. Operator, please open the phone lines for Q&A.

Thank you, Sir.

(Operator Instructions).

Our first question is from the line of Scott Hanold with RBC Capital Markets. Please go ahead.

Good morning.

Good morning, Scott.

In the Permian acquisition, can you all give us a little bit of color of kind of where those assets are located, or specifically what kind of drilling you are targeting there?

Yes, basically, they are on in an area closer to Gaines, Dawson, Andrews, Martin counties. They are targeting primarily Wolfberry, Wolf Camp, Sprayberry, so-called Wolfberry, also some deeper formations in the Atoka, the Davonian and Solarian will be tested as well in certain wells, but mainly in that so-called Wolfberry area at this point in time.

Okay, so again-- and I apologize, the line is a little choppy-- but you said Martin and Dawson companies targeting the Wolfberry is sort of the primary target?

Well Martin, Dawson, Gaines, Andrews, all through that trend area.

Okay, got it. But, most of the drilling that you see there, is that mostly vertical type of drilling? Or are you looking at some horizontal opportunities there as well?

Yes and yes.

Okay. Will you test any horizontal concepts in 2011?

We are not certain that that will happen in 2011. But, we are certainly looking at it.

Okay, great. And, when you referred to, obviously just sort of that Wolfberry type play the you were all looking at, is that relative to the 21,900 acres you just picked up? And, the reason I ask that is because it sounds like you picked up another 9,400 acres in the Permian play as well in West Texas, and does that differ in terms of what you are targeting in the areas located, or is all kinds same area?

It is all kind of the same area. There are some minor differences, but technically, yes, I think you'd be safe in assuming it's kind of in the same region.

Okay. That's great. And, what type -- I mean, it sounds like you're going to keep three rigs running on the play, it is producing about 2,800 barrels per day, what kind of growth do you expect to see out of this, say over the next year? Could you effectively start thinking about, we could try to double production here over the next 12 to 18 months?

Yes we haven't given out that kind of guidance yet, Scott. We will be giving the market more flavor on it. We need to finish closing this thing and get our hands around it a little bit better over the next 30 to 60 days We will have a little more to say about it to the markets.

Okay, great. And one more question, I guess. On the Permian, how big of a spread do you think you can expand it to? You have got roughly 90-- or, I'm sorry, 30,000 acres--how big would you like to see that, I guess, is what I'm asking?

Well, the real question isn't necessarily how big the acreage is. The real question is how we do full-cycle economics. Okay? So, it not necessarily trying to get bigger just to make it bigger, the idea is to make it profitable. That is why we chose this basin, because we think that we can do it on a full-cycle economic rate of return that makes sense and doesn't deplete our cash reserves.

Okay. Fair enough. And, one last question is, looking at the acquisition price, and obviously you have the Shell shelf assets waiting to close here, it sounds like sometime soon. How are you looking to funding this? I mean, is the first thought to put it all on the revolver? And, could we see equity in order to help sort of fund this thing from a longer-term perspective?

Well, that's two questions, but the answer to the first question is yes, we would expect that we will put it under the revolver initially. And, then how we go forward will be a function of all of our plans and acquisitions throughout the year. I don't think that this company is necessarily finished doing acquisitions. We have a lot of other things going on and if you were listening to the call there, we've got some things going on in other parts of Texas as well.

Thank you.

Thank you. The next question is from the line of David Eller with Raymond James, please go ahead.

Good morning, guys.

Good morning, David.

Just kind of still focusing on the Permian, do you think it would be reasonable to assume, using 40 acre spacing, that maybe you guys would have somewhere around 700 to 800 wells to drill in the Permian?

Oh, I don't know exactly what that account would be, I think it would probably be a little less than that, maybe 400 or 500, plus or minus a little bit.

Okay. And then, could you all talk about how many PDP or PUD locations came with acquisition? I think you mentioned maybe 70 currently producing wells?

Yes, we were talking maybe a couple of hundred.

Okay. And then, on the $35 million to $40 million Wolfberry CapEx that you mentioned in the press release, how much of that is related to drilling and completion and then how much is infrastructure related? I guess, what are you budgeting for the AFEs on these wells?

It is all related to that. It's 100%.

Okay. And then, how many gross wells would you expect you will probably drill in 2011?

We talked about that earlier, I want to say about 35, 36 wells.

Okay, and then just kind of from a big picture, logistically, this is a new area for you guys. How are you going to look at this from kind of a personnel perspective. Are you planning on opening a Midland office? Do you already have people in place, or how should we think about this being reflected in G&A?

We have people in place We also have people in our Houston office. If it's necessary to sustain that with additional operations, offices, in Midland or nearby areas, we will consider that as well.

Okay. And then, last question, was just on the rigs. I think you mentioned you have got three rigs currently running. Do any of those roll off in the next 12 months? What are the terms on those? Could you see yourself going to four or five rigs by 2012?

Those are all questions that we'll run by the market as we get our hands around this thing. Right now, we are running three rigs until the end of this year for sure. And, I would expect to see that at least that number going forward. As to increasing it, I will be able to get the market more information on that as we roll through this.

Okay. Great quarter. Thanks a lot guys.

Thank you, Sir.

Thank you. The next question is from the line of Phil McPherson with Global Hunter Securities. Please go ahead.

Good morning, gentlemen. Nice job on the quarter.

Thanks, Phil.

Tracy, what was the AFE you're looking at these Permian wells. Is it like $1.5 million or a little bit less than $1 million from the numbers you're putting out?

I don't know if we put out a general number, but I'm going to expect around $1.8 million or so, maybe $2 million, maybe $1.76 million. Depends on the well and whether we've got to go deeper targets or a little bit shallower.

And, a lot of competitors are talking about the down spacing potential here. Can you talk about what spacing your current proved reserves are on, and what kind of future spacing you think could happen with that ? You talked about a probable number of 27 million or 28 million barrels. What is that based upon?

We are thinking about 40 acre spacing here.

Great. And, with the last part of the Shell acquisition, is there something going on there as far as why it is taking so long to close, as opposed to the other properties, and when we should-- what are you thinking as far as the likelihood of it closing in the second quarter?

We think we will be done with that here in fairly short order. It's mostly regulatory issues. It's along the water, and there are still things that we have to do that need to be approved. As I've said in previous calls, it just takes a little while longer to get things done now than it did prior to Macondo.

Got you. And, you gave us a little more detail on the deep water exploratory well. Can you tell us, have you guys already submitted a permit for that? And I assume since you're 20% you're going to be a non-op?

Yes, we are going to be non-op. No, the permit hasn't been-- we are not in charge of putting the permit in. But, I expect that hopefully we will have that done in fairly short order. I'm not exactly sure on the timing, that's a function of the BOEM.

And, will you at some point tell us the operator and an idea of where it's at in kind of potential? Or, are you ready to talk about that now?

I'm not ready to talk about that now. I will talk about it when it's appropriate to do so. I will tell you that probably we are looking at a spud in the fourth quarter. Maybe late fourth quarter, as well.

All right, great. Thanks, gentlemen. Appreciate it

That is kind of the BOEM function, too.

Great.

Thank you, Sir.

Thank you.

Thank you. The next question is from the line of Richard Tullis with Capital One Southcoast. Please go ahead.

Thank you. Congratulations on the acquisition. Tracy, if you could, give us a rough split of the acreage between those four counties referenced?

Well, that's getting a little bit too specific for me, Richard. I'm not that good, but I will note that is not Toollis, it's Tullis, as I recall.

What sort of EUR expectations you guys assigning to the $1.8 million- $2 million well costs?

Yes, that's generally around maybe $100,000 or so.

Okay.

And again, it's a function of whether we are going deeper or shallower or what.

Okay. The three rigs running, are they spread out between the four counties? Or concentrated in any particular area?

You know, I just don't have that information, Richard, right now.

Okay.

But, they are not too darn far apart, I can tell you that.

The 91% oil NGLs, what percentage is oil?

It's-- oh, what you really want to know is what is the percentage of NGLs They are telling me maybe 85%, 86% oil.

Okay. Some of the call was going in and out, did Danny say current cash is around $140 million?

Yes.

Yes he did.

Yes he did.

Okay. And then, just to clarify, 2011 CapEx, is it staying at $310 million or is it going up to $345 million, $350 million?

Right now, it is staying at $310 million.

Including the $35 million, $40 million expenditure anticipated for the Permian?

That is correct.

Okay. All right, that's all for me. I will jump back in the queue. Thank you.

Okay, thanks.

Thank you. The next question is from the line of Biju Perincheril with Jefferies & Co. Please go ahead.

Good morning, guys, congratulations.

Thank you, Biju.

Tracy, if you could look forward, do you guys have a target on how much of your CapEx you would want to deploy onshore versus offshore assets?

I don't really have a specific target at this point, Biju, I mean, we will be targeting that more closely as we get our arms around this thing. But, it's not a matter of whether I want to target it between offshore or onshore, it's more of a rate of return issue.

Okay. And, on the rate of return, how does the Permian compare to your Gulf of Mexico operations on a risk-adjusted basis?

Generally you get the cash back faster offshore. That's why we like it so much. On the other hand, you get a nice, predictable reserve growth profile with the onshore stuff, and it is oil, it's not a shale play. The Permian basin has been out there for decades. And, all we are thinking is that we can look at it with a fresh set of eyes and give it a, maybe, a tweak on technology.

I think it is kind of hard for maybe the market to understand that, yes, we do drill wells out in the Gulf of Mexico. We have been drilling a lot of directional wells in the Gulf of Mexico for many, many years. The concept of drilling horizontal wells isn't a difficult thing for us to imagine. Similarly, we expect that we will employ some good petrophysics and geophysics to these projects as well. I happen to believe in both petro- and geophysics, and think that that can add something to the project, so I expect we will spend a little bit more money on the front end of the technology side of it, to make more money on the backend.

Got it. So, I guess the predictability offsets maybe slightly lower returns, but if you-- is it fair to say that you will still be pretty much committed to the Gulf of Mexico, and this is not necessarily your exit in the Gulf, moving onshore, but just adding more predictability to the portfolio?

Yes, we are not exiting the Gulf, we are just adding another basin.

Right.

There is still going to be opportunities in the Gulf for us. There is going to be opportunities in this basin, and other basins. We are growing the company. That's the point.

Got it. And, then one last question, you mentioned the Matterhorn downtime. Was that in the previous guidance? Or is that something new?

Oh, that is something new. That wasn't in previous guidance. That was a mechanical issue. There was a part of it that was in previous guidance, we knew we were going to be down a little bit for this tendon tension monitoring system, but other than that, no. Some of it was as a result of an equipment failure that was fortunately around about the same time that we were going to have to do some other additional work as well. So, we have a little bit of increase in the downtime, but not that significant.

Okay. Perfect. That's all I have, thank you.

Thank you, Sir.

Thank you. The next question is from the line of Jeff Robertson with Barclays Capital. Please go ahead.

Thanks. Excuse me, Tracy, I can't remember if you mentioned it, but how much of the 27 million BOE of proved reserves are proved producing, versus proved undeveloped?

I didn't mention that, but as I recall, we've got about 20% in proved producing at this point.

Can you talk about what kind of royalty burden these leases have, or this acreage has?

A lot of them are kind of legacy leases, but in general, probably 20% to 25%.

Okay. Thank you.

Okay.

Thank you. The next question is from the line of Jeb Armstrong with CLSA. Please go ahead.

Hello, good morning. Just a couple questions on the leases. Any issues with trough rights or lease expiration?

No. None.

Okay. That's it, thanks.

Okay, thank you, Jeb.

Thank you. The next question is from the line of Noel Parks with Ladenburg Thalman. Please go ahead.

Good morning.

Morning. How are you, Noel?

Real good, how are you?

Great.

Just a couple things. Sorry if this was mentioned before, but for the production, roughly what is the oil and gas split for the current production? In the acquired properties?

It is about 91% liquids.

Okay. So, seeing as the reserve percentage?

Yes. That is the reserves, but it is also pretty much the same way with the production split.

Okay. So, then, just looking at the mix between oil and gas in your second quarter guidance, is that largely due to the Matterhorn downtime, that the balance is actually a little bit gassier than I would've thought, given the acquisition?

Yes, I think maybe that is probably fairly accurate.

Okay. Great. And, just a couple of things about the properties themselves. Can you give us a sense of the decline profile on the properties? And also, I'm curious how long you have been working on the transaction, you know, how long you first encountered the properties and how long the negotiation process took.

It's been quite a while, I don't know the exact amount of time. The R over P be on these things is like forever. It is decades. So, in total, so what we try to focus on is ways to make that rate of return better. But, the R over P for the company is definitely going up, it will be over six point something now, with these acquisitions . I don't have that exact number in front of me. So, Jamie is telling me it took about 45 days or so to get the PSA done.

Okay. And--

And we analyzed it well before then, too. I don't have an exact date, but it was several months.

That's fine. And just my last one. The previous owner-- are these properties that they been working actively all along, or only sort of got back on in a higher oil price environment?

Well, I think that in totality, yes, these properties were worked on. I think that as we go through the process, we are going diligently through something that will proceed in an orderly fashion. There is a lot of acreage out here. They have been working on it for a couple of years before we got hold of it. But, again, we are talking about different ways that we may go forward with the properties, too.

Okay. That's it for me, thanks.

Okay, thank you.

Thank you. And, the last question is a follow-up from the line of Scott Hanold with RBC Capital Markets. Please go ahead.

Hey, just one more area of questioning. On the other stuff you're doing onshore in East Texas, and South Texas, but more specifically East Texas, I mean can you all give us a little bit of color on what you are targeting there and what the potential could be of that?

Scott, yes I could. The problem is it is fairly competitive, and I just don't really want to talk about it a whole lot. We have got some more things we want to do over there in the way of ideas. So, you will just have to wait a little bit longer. But, like I said, or like we said, we've had a significant discovery, along-- in the last well, and we think there is more in the area. So, we are going to continue to work on that basis. As we gather more information, and feel a little bit more confident in our competitive edge there, then we'll feed more information to the market. But, we are quite pleased with it.

And so, when you talk about the discovery, that's I think the Lazy Prospect down in Jackson County, is that right?

Yes, I think it is Jackson County. Is it Jackson County? I don't remember the county.

Yes. And that was expected-- that is more sort of conventional type of drilling, right? Is that more seismic kind of drilling?

That is more conventional.

Okay. And the stuff in East Texas, that you are looking at as well, is that more kind of conventional, seismic driven, or is that going to be a little bit of a mix of some other unconventional prospect activity?

It is more conventionally seismic driven. I will tell you that there is some unconventional pay in it.

Okay. And, are these more gassy or oily type of prospects?

I would say they are a little bit more toward the gassy side at this point. We will have to do some testing to find out exactly what we've got.

Okay. And, one more if I could? What approximately is the sort of acreage position in East Texas and in South Texas you have covering these areas right now?

We haven't given that information out yet.

Okay. I appreciate the information. Thanks.

Thank you, sir.

Thank you. I will now turn it back over to Mr. Krohn for any closing remarks.

That is about all for me. I appreciate you listening to our conference this morning. The company continues to grow. And, that is the point, and we are going to continue to do it, and we appreciate your indulgence. Thank you very much.

Ladies and gentlemen this concludes the conference call. (Operator Instructions) [Event Concluded]