W&T Offshore Inc (WTI) 2011 Q2 法說會逐字稿

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the W&T Offshore second 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. This conference is being recorded today, Thursday, August 4, 2011.

I would now like to turn the conference over to Ms. Janet Yang, Finance Manager. Please go ahead, ma'am.

Thank you, Operator. Good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the results for the second 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 August 11, 2011. To use the replay feature, call 303-590-3030 and dial the passcode 445-4327, pound.

Information recorded on this call speaks only as of today, August 4, 2011, and therefore time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our second quarter 2011 earning 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. Thanks for joining us for our second quarter 2011 earnings conference call.

Today I have Jamie Vazquez, our President, Steve Schrader, our Chief Operating Officer, and Danny Gibbons, our Chief Financial Officer, with us. Other members of management are here for the q-&-a session that will follow our prepared remarks.

On the last call, I told you we'd entered into an agreement to acquire acreage and production in the Permian Basin of West Texas. On May 11, we did close on the acquisition of approximately 21,900 gross lease hold acres, it's about 21,500 net acres in the Permian Basin, located in the Four Corner area of Andrews, Gaines, Martin, and Dawson counties. This is a pretty active drilling area and there's at least 22 other companies drilling in these four counties, including Pioneer, Chesapeake, Oxy, Sandridge, just to name a few. Crude reserves associated with this acquisition included 30 million barrels equivalent, or 182 BCF, and those reserves are about 91% liquids and 78% crude undeveloped.

Please note that crude reserves are based on a report that was prepared by Netherland Sewell, who are our independent reservoir engineering firm, and were actually higher than what we initially thought when we first announced this transaction, by about 3 million barrels. In addition, we're active in two other exploration project areas in the Permian Basin. Our operations in West Texas are going well. Jamie and Steve will be updating you on those operations later in the call.

We believe the move onshore in the Permian Basin's the next growth phase for the Company and one that will really benefit all of the various stakeholders at W&T Offshore. We'll be looking for opportunities for continued growth both onshore and offshore.

Well, we had a really great quarter. Our production's up, oil prices up, crude reserves are up and expenses are down. Production was up with all the deep-water properties acquired last year from Total and Shell, and with the return of our Main Pass 108 field. Our production was a bit above the midpoint of guidance, while expenses were well below the low end of guidance across the board. Production for the quarter was 47% oil and natural gas liquids, and with oil prices averaging around the $111 per barrel range for the quarter, that really makes a big impact on the bottom line. Realized price on our Gulf Coast oil sales also reflects the premium over WTI that we started realizing earlier in the year.

In the month of April alone, our oil prices were around $119 per barrel, very comparable to Brent crude. Our GAAP earnings for the quarter were $0.73 per share, which is up 97% from second quarter last year and our clean earnings, or our earnings excluding special items, were $0.71 per share, which represents an increase of 223% over second quarter last year. Our earnings for the quarter were well above the first call consensus earnings of $0.49 per share.

Crude reserves at midyear are up to 686 BCFE or 14.3 million barrels of oil equivalent. That represents an increase of 201 BCFE or 33.4 million barrels of oil equivalent over year-end 2010 and that's a percentage increase of about 41%. Netherland, Sewell & Associates, our independent petroleum engineers, assisted us in the preparation of this midyear reserve estimate.

The PV-10 value of our crude reserves, based on SEC pricing, is up over $845 million, to $2.7 billion. Crude reserves are up because of the acquisitions, positive revisions, primarily associated with the Tahoe Field, higher prices, and success with the drill bit. This is a dramatic increase in crude reserves so far this year. Our reserve mix is now 60% oil and natural gas liquids as a percentage of total crude reserves. In this type of crude oil and price environment, that's really good news to us.

With regard to our budget, as we discussed in our last call, our 2011 CapEx budget was $310 million and excluded any amounts that we might spend on acquisitions. Since the initial budget was announced, we continue to reprioritize our capital projects and expand our drilling program to include the Permian Basin wells. We still think our CapEx budget will generally be in this range.

On May 5, we closed a new four-year revolving bank credit facility with a borrowing base that currently stands at $487.5 million. The revolver and borrowing base automatically increase by $50 million when we close on the fourth Shell property, which we anticipate will be this month. Borrowing base doesn't include the crude reserves associated with the new Permian Basin properties since that transaction closed after we had finalized the new bank agreement. Those reserves will be reflected in the next borrowing base redetermination.

On June 10, we closed on a new issue of senior notes in the amount of $600 million. Notes were issued at par with at interest rate of 8.5% and they mature in June of 2019. Part of the proceeds were used to take out a portion of the $450 million of senior notes that were outstanding and the remainder was used to pay down a portion of the amounts outstanding under the revolving bank credit facility that were drawn to fund part of the Permian Basin properties acquisition.

I can't help but be pleased with what we've done so far in 2011 and believe that we are on the right track as we begin our next growth phase. I also believe that there will be more good news to come in 2011.

And with that, I'll turn it over to Jamie to expand on that a little further.

Thank you, Tracy.

I will begin by saying that our goal in 2011 is to increase the Company's production and reserves with profitable projects. Our strategy is to pursue acquisitions and drilling opportunities in areas with production and upside to support growth year-after-year. Our current focus areas include the offshore Gulf of Mexico, deep-water and shelf, West Texas Permian Basin, onshore Gulf Coast, and East Texas. We will expand these areas with projects that have good cash flow and rates of return using full-cycle economics. With the results to date, you can see that we are staying with this strategy and it looks like we're making the goals a reality.

First I want to talk about offshore Gulf of Mexico activity. The offshore drilling program is, and will continue to be, an important part of achieving our production and reserves goals this year and for years to come. Our development team continues to generate projects that add reserves and production with an excellent rate of return with low finding and development costs.

During the second quarter, we drilled the Main Pass 108 D-3 sidetrack well. The well spun on April 4, and reached total depth of 12,870 feet on April 25, logged 30 feet of net pay. The well was completed in the Tex W2 sand. Initial productions in the well was 5.1 million cubic feet per day and 143 barrels per day of condensate, net to W&T.

During the quarter we also drilled another through well Main Pass 108, the D-2 bypass 1 development well, in which we have 100% working interest. That well reached total depth 13,825 feet on June 28 and found 38 feet of net vertical pay in the Tex W6 sands. The well was completed as a single gravel pack well and is currently producing 7.9 million cubic feet per day and 187 barrels of condensate, again, net to W&T. The rig has since moved to Main Pass 108 #8 location, and is currently drilling.

We have a total of eight offshore wells planned for the remainder of the year, Three of which are exploration and five are development wells. One of the exploration wells is at Mahogany Field, where we have 100% working interest. This well should begin this quarter and will test the main field pay sand. The other two exploration wells are outside operated properties, whereby we have 40% working interest in one, and 30% in the other. Because we are not the operator of these wells, we don't know the exact timing of when operations will commence. One of the wells that we drill will be from existing infrastructure so we might get a small amount of buildup in 2011 but the other well will need additional infrastructure, if successful.

We thought we were going to drill a deep-water exploration well this year, but all indications are, is that we'll spend the first half of 2012. As for the five offshore development wells, we are the operator and have 100% working interest in four of the five wells. Development wells are located in Ship Shoal 349, Mahogany Field, the Main Pass 108 field, and the South Timbalier 314 field. As you can tell, this is an active offshore program that will take us into 2012.

Let's talk a little bit about our onshore activities. In East Texas, we recently drilled a well in which we have a 35.4% working interest and we're the operator. This well was drilled to a total depth of 16,800 feet, targeting both conventional and unconventional reservoirs. The rig is still on location and we're setting pipe for further evaluation. There may be additional development opportunity around the area.

In South Texas, we recently participated in the drilling of a well 16,000 feet, located in Wharton County, Texas. Unfortunately, the well didn't find commercial hydrocarbons and we have subsequently plugged and abandoned the well.

Now let's talk about the Permian Basin. We have three distinct drilling projects in the Permian Basin. First, as we discussed earlier, we acquired 22,000 gross acres in a four county area of West Texas, that includes Dawson, Gaines, Andrews, and Martin Counties.

There are between 450 and 500 drillable well locations, based on 40-acre spacing. Seventy-three of these wells were drilled on the acreage prior to closing. We typically have three rigs in the field but at the moment we've added a fourth rig to drill two wells. We expect to go back to the three rig program for the remainder of the year. Now that we've established operations in the Permian Basin, we are looking or additional projects in the area to expand our activity.

Since closing on May 11, through the end of the second quarter, we drilled nine wells. The average cost of each well was $1.9 million per well, which includes completion and it took an average of about 19 days to drill each well. Usually it takes another 20 days after reaching total depth before we can get fracking crews in and then it takes about two days to complete. In this specific area of the Permian, we expect to drill between 20 and 25 wells in the third and fourth quarters, and spend between $40 million and $50 million, including the completion. All these wells are focused in Wolfberry Trend with well depths around 11,400 feet.

In the second drilling project area in the Permian Basin, we intend to participate in the drilling of about eight exploration wells during the second half of the year. We'll have about 32.5% non-operated interest. There are currently two rigs on location in the area. One well has already reached total depth and the second well is near total depth, both targeting the Wolfberry section. If these wells prove successful, more wells will follow to develop the 5,300 gross acres that we have leased in the area.

There's also a third drilling project area that we've identified and are working in the Permian Basin. We're the operator and we plan to drill three well exploration programs targeting the Wolfberry that will commence on or about September 1. The wells will be drilled to a depth about 12,000 feet. If these wells are successful, we would expect to kick off a development drilling program in the area. We have an 80% working interest and about 11,270 gross acres under lease.

What I haven't discussed is horizontal wells. All the wells described in the Permian Basin projects are vertical wells with the multistage frac completion. We are working on the design of horizontal wells and frac methods and are determining the best areas from a geologic perspective. Once we have done that, we will give the market more information on timing.

Next, let me give you what I hope to be the final update on the fourth Shell property that we have been discussing since last year. As you will recall, we entered into a letter of intent with Shell to acquire a fourth property. The property's comprised of a 64.3% working interest in the field, located in shallow waters of Gulf of Mexico and related ownership interest in an onshore gas treatment plant. This transaction is expected to close in the next couple of weeks. Purchase price is around $42 million, subject to customary closing adjustments. Production has run about 18 million cubic feet per day, net, and is primarily gas. This production is not included in our guidance.

Let me update you on the capital budget. The capital budget for 2011 is $310 million, excluding acquisitions. Thus far we've spent about $85 million for exploration and development activities, which includes land and seismic purchases. The remainder of the year we'll be really busy and we will have an upwards of four rigs working offshore and, at some time, six rigs working onshore.

On the acquisition side, we've spent around $400 million for the first half of the year and will spend about $42 million on fourth Shell property in the third quarter. In summary, we will continue to evaluate drilling and acquisition opportunities in both the Gulf of Mexico, deep-water and shelf, and the onshore.

With that, I will turn it over to Steve Schroeder to update you on the operations.

Thanks, Jamie.

As we've discussed in the past, our strategy when purchasing an asset is to identify upside and/or overlooked value to enhance the future value of the asset. We've either completed or are progressing forward on several projects, which are enhancing the value of recently purchased properties.

First, at Matterhorn, we have just finished a recomplete, whereby we changed reservoirs in the A-7 well. The well is currently flowing 9.4 million cubic feet per day and 392 barrels of oil per day, net. As a follow-up to last quarter's call, we completed the repairs to the facility and we refurbished the tendon tension monitoring system. Both projects came in on time and below projected cost.

During the second quarter, we finalize an agreement with a third-party to process production at Matterhorn facility. The subsea development will use the spare capacity in the facility and will generate processing revenues, which will help bring down our cost.

Finally, we have submitted the first permit required to allow W&T to mobilize a platform rig to drill at Matterhorn. Our current expectation is to mobilize toward the end of the fourth quarter and began drilling soon afterward.

Second, at Tahoe, we're working on an optimization project to add compression at the host platform where our Tahoe production flows. The project has been sanctioned and as a result, we have been able to increase crude reserves associated with this project. Not only does this project increase crude reserves, it also increases production an estimated 5 million to 10 million cubic feet equivalent per day, net, in the fourth quarter.

Lastly, in our Permian Basin acquisition, we have operated the field for less than two months. We have assembled a team with the sole focus of developing the field while enhancing the value. Our sales from this area averaged around 2,500 barrels per day of oil equivalent during June, as there were quite a few wells off-line during the month for a variety of operational reasons.

Since taking over operations, the team has made a number of remedial changes, namely modified the casing design of new wells, increase the size of pump jacks, revised the rod design for wells, and altered the way in which we float wells back after fracking. As an example, under the previous method, wells took between two and three months to flow back the frac fluid. We've modified the equipment and the flowback period has been decreased to two to three weeks.

Also, we are working to install remote-control systems to monitor each well's lift system to reduce future workover expenses. We have addressed most of these operational issues and current production is over 2,800 barrels of oil equivalent per day. We're not satisfied with the way frack treatments have traditionally been done in this field and are working to make improvement to this process. Additionally, we've established a field office to help implement our future operational plans in the area. We're committed to optimizing these assets and are taking the steps necessary to maximize long-term profitability.

Let's talk about Main Pass 108 field. Between the wells that existed before the pipeline was shut down, the wells added in the Main Pass 108 field and the wells added in the Main Pass 98 and Main Pass 180 areas that flow into the Main Pass 108 pipeline, our production is now at 40 million to 45 million cubic equivalent per day, net, of which 17% is oil. Additional development in this field includes Main Pass 108 #8 well, which is currently being drilled to known field pay. We expect to have another one to three wells to drill before we complete this program. The rig in the Main Pass 108 area has been continuously drilling since February 2010, which has truly been an accomplishment, considering the regulatory environment over the past year.

Let me discuss our recompletion and workover program. Overall, for the first half of 2011, we have performed 16 recompletes and 23 workovers offshore that added net incremental production of approximately 26 million cubic feet equivalent per day, at a cost of about $21 million. We're nearly complete with the West Delta 30 field for well recomplete program. Three wells are complete and have added approximately 460 barrels of oil per day, and 500,000 cubic feet per day, net. We will be mobilizing two platform rigs during the month of August, one to Mahogany and one to the South Tim 314 field.

The Mahogany program is expected to be either three or four wells. The program should continue well into 2012 and we project 1,500 barrels of oil per day and 2 million cubic feet per day, net average buildup, from each of these wells.

The South Tim 314 program is a mixture of a sidetrack, a recomplete, and a workover. This project is expected to add approximately 500 barrels of oil per day and 800,000 per day of net production. Both of these programs will focus on work to develop oil reservoirs. As Jamie said, we should be really busy the second half of the year.

Moving on to production guidance. For the third quarter we anticipate our oil and natural gas liquids production to be between 1.8 million and 2 million barrels, and our natural gas production to be between 12.1 and 13.4 BCF, and our total production to be in the range of 23.2 to 25.6 BCFE, or 3.9 million and 4.3 million barrels of oil equivalent. Production guidance does not include any anticipated production associated with the Shell property to be acquired from Shell. It does include an estimate of five days possible downtime associated with hurricanes.

For all of 2011, we anticipate our oil and national gas liquids production to be between 7.3 million and 8.1 million barrels and our natural gas production to be between 48.7 and 53.8 BCF, and for a total production for the year, to be between 92.7 and 102.5 BCFE, or 15.4 million and 17.1 million barrels of oil equivalent. You will note that this represents an increase in annual guidance due to better than anticipated well performance, increased activity, and the compressor project at Tahoe. Obviously, when we close the fourth Shell property, the guidance should advance further.

Our guidance for the lease operating expenses for the third quarter of 2011 is between $56 million and $62 million, and for the year our guidance hasn't changed, and is between $190 million and $220 million. These estimates do not include any allowance for hurricane-related expenses or insurance reimbursements.

We had a great second quarter relative to expenses but we are entering the favorable part of the year for conducting repairs and maintenance, considering the days are longer and the weather more favorable, and as such, have shown an increase in expenditures from the second quarter. For example, we have eight active sandblast and paint crews working. In addition, the third quarter will be the first quarter to have West Texas properties added to the portfolio and our new insurance premiums.

Our guidance for gathering, transportation, and production taxes for the third 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 second quarter results.

Thank you, Steve.

Revenues for the second quarter were $252.9 million and that's up $73.3 million from second quarter last year. It's due to high oil prices and higher volumes. The second quarter really benefited from higher oil sales, which in turn, lead to higher earnings. Crude prices were $111 per barrel, and that compares to $76.27 per barrel in the second quarter last year.

The second quarter also benefited from higher production volumes. Production in the second quarter was 24.8 BCFE, and that's compared to 22.8 BCFE in the second quarter last year.

Production was higher as we had a full quarter of production from all the properties that we acquired from Shell and Total in 2010, and the Permian Basin properties in 2011. Sales volumes also benefited with the return to production of various fields that were shut in by the pipeline outage in the Main Pass 108 field. These fields returned to service on March 31, 2011, when the pipeline that connects Main Pass 108 field came operational.

Let me move on to lease operating expenses, if you will. We look at LOE in five different components, that's base LOE, insurance premiums, workovers, facilities work, and then hurricane remediation. In the second quarter 2011, LOE decreased to $48.6 million, or $1.96 per MCFE, from $52.5 million, $2.30 per MCFE, in the second quarter of last year.

On a component basis, all costs declined with the exception of facilities expenses, which increased due to the work on the tendon tension monitoring system and mechanical repairs at Matterhorn. Base LOE was down $2 million. Insurance premium were lowered by $1.8 million. Hurricane remediation costs net of insurance reimbursements were down $2.6 million. The workover expenditures were down $1.5 million.

Moving on to DD&A. For the second quarter, DD&A on a per-MCFE basis, was $3.36, up slightly from $3.33 per MCFE in last year's second quarter, primarily a result of the acquisition of the Permian Basin properties. On a nominal basis, DD&A increased to $83.4 million in the second quarter, and that's compared to $76 million in the second quarter of last year. It's all due to higher production volume and slightly higher DD&A rate.

G&A, our general administrative expenses, were $18 million in the second quarter of this year, compared to $14.4 million in the second quarter of last year. The increase in G&A relative to last year's is primarily due to higher incentive compensation and that's associated with the achievement of the company of pre-determined performance targets, while we also have reduced overhead charges billed to joint interest owners, and slightly higher salary cost. No amounts for incentive comps were paid in the second quarter of 2010, based on 2009 results.

During 2010, we implemented a new incentive comp plan and part of the incentive comp 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 targets. Our guidance for G&A for the third quarter is between $19 million and $21 million, and for the year, between $71 million and $79 million.

Let's talk about the financial performance for the second quarter of 2011. We reported net income of $55.2 million, or $0.73 per share, compared to $27.9 million, or $0.37 per share, in the second quarter of last year, and more than doubled that reported last quarter. Adjusted to exclude special items for the same periods, net income was $53.4 million, or $0.71 a share, compared to $16 million, or $0.22 a share, in last year's second quarter. Also keep in mind that our effective tax rate this year is 35.1%. Last year's was only 8.7%, with the reversal of the valuation allowance throughout 2010. The special items are explained in our second quarter earnings release.

Adjusted EBITDA was $175.6 million, that's up 93%, or $84.7 million, from the second quarter 2010 and up $133 million sequentially. Net cash provided by operating activities for the first six months of 2011 is $229.8 million and that compares to $244.3 million in the first six months of last year. Keep in mind that we received a tax refund from the United States Treasury of almost $100 million in the second quarter of last year and paid out $19 million in the second quarter of this year. Otherwise cash flow from operations is up significantly. It has substantially improved operating results.

As Tracy mentioned, on May 5 we closed on the new four-year revolving bank credit facility, with the borrowing base revolver size of $487.5 million, and on June 10, we closed on a new issue of senior notes in the amount of $600 million. Part of the proceeds were used to take out a portion of the $450 million in senior notes that were outstanding and the remainder was used to pay down a portion of the notes outstanding under the revolving bank credit facility.

On June 30, only $405.6 million of the total $450 million in senior notes had been redeemed, so that is why there's some carryover amount outstanding at the end of the quarter. Subsequently, the remainder have been redeemed on July 18, so now the entire $450 million of the 8.25% senior notes are now redeemed. Included in earnings for the second quarter is a pretax charge of $20.7 million, related to the early redemption of the 8.25% senior notes and the new bank deal.

Our cash and equivalents to June 30, was $8.7 million and we have $75 million outstanding under the revolver. Our liquidity continues to be strong and will allow us to continue to avail ourselves of the growing list of opportunities that will allow us to grow with the Company.

Moving on to asset retirement obligations, expenditures for ARO for the first half of the year is $29.7 million and insurance reimbursements related to that was $18.5 million. We expect to make an additional recovery in the future as we perform plug and abandonment work on facilities and platforms that were damaged during hurricane Ike.

Our effective tax rate for 2011 is expected to be in the range of 35% to 36%, all of which will be deferred except for an amount related to alternative minimum tax, which will require a small cash payment. The rate forecast reflects not only the federal statutory rate, but also the amount of state taxes related to our Permian Basin production.

Our effective tax rate is up considerably from last year, again, but we were able to completely reverse the previously established valuation allowance, which reduced tax expense throughout 2010. Finally, no hedges were added during the second quarter to our hedging positions. They're all related at approximately 16% of the remainder of our 2011 NGL production is hedged.

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

Thanks, Danny.

As you can tell, we had a great quarter with high production volumes, higher oil prices, big increase in crude reserves, and lower costs. The prices that were receiving for our Gulf Coast barrels better mirrors Brent crude prices rather than WTI, which is a real positive for us and one of the attributes to our Gulf of Mexico production.

We've entered into the next growth phase of the Company and look forward to additional growth throughout this year and beyond. And just because we've moved onshore, we haven't stopped working in the Gulf of Mexico and, in fact, quite the contrary. We have a lot going on out there, as Jamie described, and some of the things that we're focused on will lead to additional opportunities going forward.

We're very active in West Texas and expect that to increase the rest of the year. As you heard from the production guidance, we have increased our annual production guidance and should expect further increases in production with the close of the fourth Shell property, hopefully coming up this month.

We'll grow reserves in 2011and increase production over 2010 levels. We still believe in cash flow and full-cycle economics. We like the idea of more predictable growth as well. We believe that there will be additional track of acquisition opportunities for us, both onshore and offshore.

I'd like to remind the market, once again, that we didn't sell equity over last few years, in fact, we actually bought back a few shares. As already discussed, we have a new revolver, a recently completed senior notes offering, and a strong liquidity position.

As we think about the remainder of 2011 and beyond, we expect to continue to expand our operations in West Texas, East Texas, the Gulf Coast region, and the Gulf of Mexico.

With that will take your questions, and Operator, if you would please open the phone lines for Q&A.

Thank you, sir. We would now begin the question-and-answer session.

(Operator Instructions)

One moment please.

(Operator Instructions)

Looks like the market's tanking and everybody's out trying to figure out what to do about their portfolio. We'll hold it open here for another minute or two, but I imagine they're all out trading shares for the whole world. Hopefully, they're out buying our shares too.

Okay. We appreciate it and we'll talk to you next time. Thanks very much.

Ladies and gentlemen, that does conclude the W&T Offshore second quarter earnings conference call. If you would like to listen to a replay of today's conference, please dial 303-590-3030 with the access code of 445-4327.

Thank you for your participation. You may now disconnect.