W&T Offshore Inc (WTI) 2006 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the W&T Offshore fourth 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 Thursday, March 8, 2007. At this time I would like to turn the presentation over to Manuel Mondragon, the Vice President of finance.

Thank you, operator. Good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the fourth quarter and full year 2006 results. Before I turn the call over I have a few items I would like to go over. If you would like to be on the company's e-mail distribution list to receive future news releases or you experience a technical problem and did not receive yours to this morning, please call DRG&E's office at 713-529-6600 and someone will be glad to help you there. If you wish to listen to the 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 March 15, 2007. To use the replay feature, call 303-590-3000 and dial the pass code 11085913.

Information recorded on this call speaks only as of today, March 8, 2007, and therefore time sensitive information may no longer be accurate at the date of any replay. Today management is going to discuss certain topics that contain forward-looking information which is based on management's beliefs as well as assumptions made by and information currently available to management. Forward-looking information includes statements regarding expected production expenses for quarterly and full year 2007. Although management believes that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks, uncertainties, and assumptions including among other things market conditions, oil and gas price volatility, uncertainties inherent in oil and gas production operations, estimating reserves, unexpected future capital expenditures, competition, and the success risk management activities, governmental regulations, and other factors described in the company's most recent annual report on form 10-K and subsequent filings with the Securities and Exchange Commission.

Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially from those expected. Please also note that this conference call contains references to non-GAAP financial measures. You can find reconciliations of these non-GAAP financial measures to GAAP financial measures in the form 8-K filed by the company earlier today as well as in this morning's press release. Now I would like to turn the call over to Mr. Tracy Krohn.

Thanks, Manny. Good morning, everyone. I'd like to thank you for joining us for our fourth quarter and full year 2006 conference call. Again, I am Tracy Krohn and this morning I will discuss certain key events that took place in the fourth quarter and for the full year 2006. With me is some of our team joining us for the first time Danny Gibbons, our recently named CFO. Danny is going to review financial results for the fourth quarter and 2006. Steve Schroeder, our Chief Operating Officer, will touch on the progress of fourth quarter 2006 drilling projects and operations. Cliff Williams, our VP of reservoir engineering, will review our 2006 year-end reserve report and 2007 production guidance. Then I will turn it over to Jeff Durrant, Senior VP of exploration and geoscience, who will update you on our 2006 drilling successes and preview our 2007 program. Following our formal presentation, we will also have a Q&A session.

While 2006 was a notable year for W&T to say the least, we completed a major transaction with Kerr-McGee for a big, just over $1 billion for which we assumed operations on October one. We completed a follow-on offering of our common stock of just over $300 million and as we mentioned in this morning's press release, we had a record year in production. We achieved new company highs in production, revenue, cash flow, reserves, and adjusted EBITDA during 2006. The year-over-year production increased 40%. Revenue grew 37% and adjusted EBITDA grew 36%. Our adjusted EBITDA margin for 2006 was 80%, compared to our five-year weighted average of 78%. Cash flow from operating activities increased 29% in 2006 to $572 million in 2006 from $444 million in 2005.

Well, not only did we complete a large transaction, we complemented that with another successful year with the drill bit. For 2006 we were successful in 19 of 26 exploration wells for a 73% success rate. Our five-year success rate for exploration is 77%. In 2006, we were 100% successful on development wells with 8 out of 8 successful wells. This is the third year out of the last five that we had 100% success in development wells. On a combined exploration and development basis, we had a 79% drilling success rate this year.

On the reserve side with the drill bit alone our team was able to essentially replace our production. I can report that Tuesday we entered into written settlement agreements with our insurance underwriters whereby we have settled all claims for Hurricanes Katrina and Rita and Green Canyon 82 for approximately $105 million. After adjustments for applicable deductibles and amounts already collected for previously submitted claims, the company will receive net proceeds of $73.3 million currently expected for the middle of March 2007. We are pleased to have the process behind us. It allows us to recover all of our expenditures booked through December 31, 2006.

Speaking of hurricanes, with the current impairment of our production due to the hurricanes -- excuse me -- a lot of the current impairment of our production due to these hurricanes is not significant, the remaining repairs will continue this year as we plan and implement the work, including obtaining the necessary permits. We anticipate spending between $15 million and $20 million for remaining hurricane remediation in 2007. We will continue to give updates regularly so that you can distinguish between normally recurring LOE and our LOE related to the hurricane repairs.

As you saw in this morning's press release, our earnings per share was $0.50 versus the consensus of $0.80. The primary difference is the street's estimate for topline revenue. The street expected production to exceed the high side of our guidance and also assumed a higher price deck. The combination of higher production and higher realized prices contributed to the majority of the differences between the street estimates and our reported figures. Had the consensus been closer to our guidance, we believe we would have made the street estimate for our EPS number. Ironically our cash flow per share is actually higher than the consensus was. The consensus was 271 compared to our number of 285.

Expenses are in line with our guidance as previously stated. I have been asked many times by investors what we think is the most important parameter relating to an evaluation of W&T. That answer is that the hallmark of this company is turning reserves into cash and we manage this company for cash flow. Now I'm going to turn it over to Danny Gibbons to expand on the financials further.

Thank you, Tracy. It is appropriate to remind you when reviewing year-over-year numbers that the fourth quarter of 2005 saw the greatest production impact due to the hurricanes. Now let me talk about net income. Net income for the fourth quarter of 2006 was $38.1 million or $0.50 per diluted share on revenue of $264.4 million. This compares to net income of $50.9 million or $0.77 per diluted share on revenue of $152.9 million for the fourth quarter of 2005. Net income for the year 2006 was $199.1 million or $2.84 per diluted share on revenues of $800.5 million. Again this compares to net income of $189 million or $2.87 per diluted share on revenues of $585 million for the year 2005. Included in the full year 2006 results are realized and unrealized commodity derivative gains of $10.8 million and $13.4 million respectively. There were no derivative gains or losses in 2005. Net income was affected in the fourth quarter and full year 2006 due to higher operating expenses and increased interest expense.

Now let's move on to lease operating expenses. Lease operating expenses for the fourth quarter of 2006 was $43.2 million compared to $19.5 million in the fourth quarter of 2005, but on a per unit basis lease operating expense decreased to $1.20 per Mcf equivalent during the fourth quarter of 2006 from $1.43 per Mcf equivalent during the fourth quarter of 2005. Lease operating expense for the full year of 2006 was $109.7 million or $1.11 per Mcf equivalent compared to $71.8 million or $1.01 per Mcf equivalent in 2005.

The increases in the quarterly and year-to-date LOE are primarily attributable to higher costs associated with properties acquired in the Kerr-McGee transaction completed in August of 2006, a substantial increase in insurance premiums as a result of the 2005 hurricanes, and an overall increase in service and supply costs at existing properties.

Moving on to depreciation, depletion, amortization, and accretion of asset impairment costs, we refer to that as DD&A. That amount was $135.7 million or $3.79 per Mcf equivalent in the fourth quarter of 2006, and represents a $90.7 million increase over the comparable period of 2005. For the full year of 2006, DD&A was $337.6 million or $3.40 per Mcf equivalent compared to $183.8 million and $2.59 per Mcf equivalent for 2005.

Going into a bit greater detail, the total amount of oil and gas properties, future development costs, and future plugging and abandonment expenditures subject to DD&A was approximately $2.7 billion in 2006 versus $1.2 billion in 2005. That represents 125% increase over 2005. However, the reserves associated with that base increased to 735 Bcf equivalent in 2006 from 492 Bcf equivalent in 2005 or 50% increase. Therefore the total depleteable cost increased at a much higher rate than the reserve base, resulting in a greater DD&A per Mcf equivalent.

Moving on to cash flow from operating activities and EBITDA, net cash provided by operating activities was $220.1 for the fourth quarter of 2006, up 120% from the prior years' fourth quarter. Fourth quarter adjusted EBITDA was $207.7 million, up 71% over the comparable period. For the year 2006, net cash provided by operating activities increased 29% to $572 million and adjusted EBITDA was $642 million, up 36%. Our adjusted EBITDA margin for 2006 was 80%, compared to our five-year adjusted weighted average of 78%.

Talk about pricing for a moment. For the fourth quarter of 2006 the natural gas price averaged $6.64 per Mcf and crude oil averaged $52.13 per barrel. That comes to an average of realized price of $7.38 per Mcf equivalent. This compares to an average realized price of $11.20 per Mcf equivalent in the fourth quarter of 2005. For the year, our average realized sales price was $8.07 per Mcf equivalent, compared to $8.23 per Mcf equivalent in 2005.

Moving on to G&A, for the fourth quarter of 2006, G&A expenses increased to $11.7 million or $0.33 per Mcf equivalent from $9.2 million for the fourth quarter of 2005. This is mostly due to increased number of employees and bonus accruals during the 2006 period to be paid in 2007. For 2006, G&A expenses increased to $42.1 million from $28.4 million in 2005. On an Mcf equivalent basis, G&A expense was $0.42 in 2006 compared to $0.40 in 2005. This represents an increase of only 5% while production increased 40% over the same time frame. Also contributing to higher G&A expenses in 2006 were increases in personnel costs and professional fees associated with regulatory requirements such as Sarbanes-Oxley.

Moving on to interest expense, for 2006 interest expense $30.4 million. Capitalized interest was $13.2 million and interest income was $5.9 million. Interest expense increased due to an increase in borrowings to fund the Kerr-McGee transaction. Talking about income taxes, income tax expense was $21.7 million in the fourth quarter of 2006 and $107.3 million for the year. That results in a current provision of $600,000 and a deferred tax provision of $106.6 million. Our effective tax rate for 2006 was approximately 35% and we expect that to remain the same for 2007.

At December 31, 2006, we have $15.7 million of income taxes receivable classified in current assets. This resulted primarily from increased intangible drilling costs that are capitalized for book purposes but deductible currently for tax purposes. We expect to defer approximately 80% of book taxes in 2007. Talking about capital expenditures, for the year ended December 31, capital expenditures of $1.7 billion, that included $1.1 billion for the acquisition of the Kerr-McGee properties, $301.6 million for development activities, $252 million for exploration, $35.4 million for seismic and other leasehold costs, and $4.8 million for other capital items.

In closing I will talk about the balance sheet. At the end of 2006 we had $39.2 million in cash and cash equivalents and $685 million in debt. Total assets were over $2.6 billion, up from $1.1 billion in 2005. You will see in our form 10-K that at December 31, 2006 we still carried approximately $75 million in Hurricane receivables. This amount will be offset by the insurance settlements referred to by Tracy and detailed in the earnings release.

Shareholders equity increased from $543 million in 2005 to over $1 billion at the end of 2006. Our debts to total cap ratios stood at 40% and our 2006 adjusted EBITDA to interest coverage was over 21 times interest expense. With that let me turn it back over to Tracy.

Thanks, Danny. As you can see, W&T enjoyed another successful year financially and we had record cash flows. We were able to maintain our historically high EBITDA margin of around 80%. As a result of the Kerr-McGee transaction, W&T has committed itself to an aggressive debt repayment schedule. In 2006 we are scheduled to pay off the remainder of our term A loan. As I said before, paying off debt and delevering quickly puts us in a ready position for future opportunities either by acquisition or with the drill bit.

A little note on rig availability. As I suggested on our prior conference calls and investor presentations, rig rates are going to fall and as predicted they are falling as we speak. As a matter of fact we have contractors contacting us about rig availability frequently. I see no issues in getting the types of rigs needed for our 2007 drilling programs.

Turning now to operations, I am really pleased at how our staff has worked to achieve a smooth transition in integrating the Kerr-McGee properties, which is our number one priority for 2007. We took over completed operations as of October 1, 2006 and we continue to integrate these properties as we have in our prior transactions.

Now Steve Schroeder, our Chief Operating Officer, is going to update you on our current operations, status of our hurricane repairs, and operating guidance details.

Thank you, Tracy. As discussed in the previous conference call, the integration of the Kerr-McGee properties with our heritage properties has been and will continue to be a key focus of our operations staff in 2007. It all begins with people and we have been fortunate to retain a significant number of Kerr-McGee operators, making the transition in the fields fairly smooth. We continue to add office staff in several departments including reservoir engineering, production engineering, in geosciences and land. Operationally the field personnel have brought online a number of wells that went off production during the transition period, and engineering has identified and executed several workovers in the Kerr-McGee fields.

We have drilled our first successful well in a former Kerr-McGee property at Highland 22 and are currently drilling our second well at another location. Consistent with what Tracy said in previous discussions, the Kerr-McGee merger had several drill ready prospects and these wells are proof. However, even with the early successes in the Kerr-McGee properties and as Jeff will discuss later, we view 2007 is an information gathering year preparing W&T for the future.

To update you on our drilling program, we are operating two rigs at this time, one semisubmersible delineating our deep water Healey discovery and one [mat] cantilever rig at West Cameron 181. The Healey #3 was successfully deepened and we are obtaining additional data as we speak assisting in our evaluation of the discovery. Recently we released a semisubmersible after successfully completing the well developing our Cypress discovery. Additionally we have a nonoperating interest in a well drilling an offset to last year's Highland 24L discovery.

During the second quarter we plan to contract a rig for an operated multi-well workover program. Consistent with what Tracy said earlier, I see no issues in getting the types of rigs required for our 2007 work program. Fourth quarter of 2006 and first quarter of 2007 have been challenging because of severe weather conditions and equipment availability that we mentioned in our last operations update. Of particular note, diving operations have been particularly difficult.

We did bring online two major projects, namely Queen of Hearts and Grand Isle 3. Queen of Hearts is making over 2600 barrels of oil per day gross or 15 million cubic feet equivalent per day net. And the nonoperated Grand Isle 3 is making 18 million cubic feet per day gross or 4 million cubic feet equivalent per day net.

We continue our hurricane remediation related construction projects. At East Cameron 321, a third party is repairing the export pipeline. Once the pipeline has been repaired, we project an additional 20 million cubic feet equivalent per day net from the field. We have completed all the underwater repairs at our most significantly damaged platform, East Cameron 338A. A majority of the topside equipment has been purchased and we've started installing the facilities kits. Relative to the former Kerr-McGee properties, only one repair is noteworthy relative to production impact, a gas supply well in the Brenton Sound 20 field was damaged during Hurricane Katrina. Kerr-McGee secured the well and a plan has been developed to repair the well and restore production.

I would like to take a brief moment to elaborate on our expense guidance. We anticipate normal recurring lease operating expense for 2007 to be between $167 million and $199 million and another $15 million to $20 million for lease operating expenses related to Hurricane remediation efforts. The increase in normal recurring lease operating expenses is due to a full year expenses associated with the Kerr-McGee properties, higher insurance premiums, and higher workover costs and facility expenses related to the integration of the Kerr-McGee properties.

The costs of gathering transportation and production taxes are anticipated to be between $25 million and $30 million, which is an increase over 2000 expenses due to higher sales volumes. Back to you, Tracy.

Thanks, Steve. I think you meant to say 2006 expenses, thanks. As Steve pointed out, we're focused on integrating the Kerr-McGee properties and are very pleased with the progress to this point. Again this is going to be our primary operating focus in 2007. As Cliff will detail shortly, we had an excellent year with our development drilling, eight out of eight wells for 100% success rate. We also had a year of record production with a 40% increase over 2005. An all in reserve replacement rate of 346% was achieved with our recent acquisition and our successful drilling program.

Our reserves grew from 496 Bcf at year-end 2005 to 735 Bcf equivalents at year-end 2006. Excluding the Kerr-McGee transaction we were able to essentially replace our production. Production for the fourth quarter 2006 was 390 million cubic feet equivalent per day, a 163% increase over fourth quarter 2005. We have noticed that other companies have incurred ceiling test write-downs for 2006. Want to let you know that under our PV-10 test we have no ceiling test issues; in fact we have substantial room under the test.

Now here is Cliff Williams, our VP of reservoir engineering, to discuss our year-end reserve report, our 2006 development drilling, and to preview some of the development projects for 2007.

Thanks, Tracy. As Tracy just pointed out, our crude reserve base in 2006 increased by 50% to 735 Bcfe from 492 Bcfe at year-end 2005. And for 2006 our reserve replacement rate is 346%. As you may be aware, Netherland & Sewell Associates, our independent petroleum consultant performs a grass-roots review of our proved reserves each year. We replaced 110% of our 2006 production through the drill bit and extensions. Reserves acquired through the Kerr-McGee merger accounted for the majority of the remaining reserves replaced.

Revisions of -13 Bcfe were the combined results of a decrease in gas price from year-to-year, the debooking of several PUDs, two following a detailed field study and another based on the results of a noncommercial exploration well. These negative revisions were offset by the 14.1 Bcfe of reserve adds, which is over half these negative revisions resulting from better than forecast performance.

Our reserve replacement cost or RRC for 2006 is $5.21 per Mcfe. We define RRC as all costs incurred during the year for proved and undeveloped acquisitions, plus development, exploration and ARO costs divided by all reserve additions including revisions, extensions, discoveries, and acquisitions. This calculation does not include future plugging and abandonment or future development costs. Our three-year rolling RRC average is $4.47 per Mcfe. We believe both of these calculations compare very favorably to our peers.

Full year 2006 production of 99.2 Bcfe was within our most recent guidance. For 2006 our production mix was 61% gas and 39% liquids. There are several projects that affected fourth quarter 2006 production as well as first quarter and full year guidance for 2007. At East Cameron 321 field, progress is completing in completing repairs by the gas sales pipeline owner has been slower than previously expected. Startup of this pipeline has been delayed from mid-December to mid-March, a deferral of 0.3 Bcfe in 2006 and 1.6 Bcfe in 2007. As Steve mentioned, third party repair operations are underway and we anticipate these repairs will be complete shortly.

An unanticipated field shut in due to a parafin plug and the departing oil sales pipeline at the W&T operated South Tim 316 field occurred in late November resulting in the deferral of 0.2 Bcfe in 2006. Two unsuccessful attempts have been made to clean out the pipeline with coil tubing. We are planning a more extensive intervention at this time, which could involve the replacement of a section of pipeline in order to allow the pipeline cleanout operation to proceed. We anticipate this field to be back online in the third quarter of this year.

In late December 2006, the pipeline segment in the High Island Pipeline System was severed, resulting in the unanticipated shut-in of three W&T operated and five nonoperated fields in the High Island area through the end of January. Net production from these fields sums to 1500 barrels of oil per day and 5.8 million cubic feet of gas per day, or 15 million cubic feet equivalents per day. We estimate approximately 0.4 Bcfe has been deferred in 2007 due to this unanticipated event.

To update you on hurricane production, in 2006 we were forced to defer companywide production of approximately 7.7 Bcfe as a result of Hurricanes Katrina and Rita. Approximately 10 million cubic feet equivalent per day, which is less than 2.5% of our estimated guidance, remains shut-in as a result of these storms. We anticipate these repairs to be complete by the end of 2007.

Production guidance. The company is reducing the low end of our first quarter production guidance by 5.6%. As a result of production deferrals from project completion delays mentioned earlier, pipeline issues and prior period adjustments in the fourth quarter, the Company anticipates first quarter production will approach the low end of between 1.86 and 2.17 million barrels of oil and between 20.75 and 22.8 Bcf of gas. As stated in our last operational update, the Company anticipates full year 2007 production to be at the low end of the original range of between 9.6 and 10.5 million barrels of oil and between 92.2 and 101.2 Bcf of gas.

Even at the low end of this guidance, we anticipate an increase of 50% over 2006 production. Other projects impacting 2007 production include Ewing Banks 949, our Queen of Hearts prospect. This successful 2005 exploration well drilled in 850 feet of water was recently brought online at a net rate of 2200 barrels of oil per day and 1.8 million cubic feet of gas per day. This is a 100% W&T deepwater well. At Grand Isle 3 this deep shelf prospect was recently brought online at a net rate of 3.3 million cubic feet of gas per day and 100 barrels of oil per day.

At High Island 22, we recently completed a successful shelf exploration prospect, the B3 Sidetrack, on an original Kerr-McGee property. The well was brought online at a net rate of 5.4 million cubic feet of gas per day and is a 100% W&T well. There are several other projects already drilled and waiting on final facility work to be completed including shelf discoveries at Galveston 303, High Island 24L, Main Pass 185, South Timbalier 299, and Mobile Bay 824. A deep shelf discovery at Bay Junop in the inland waters of Louisiana and a deepwater discovery at Ewing Bank 989. Anticipated buildup from these discoveries sums to 48 million cubic feet equivalent per day to be added in the second and third quarter timeframe. Back to you, Tracy.

Thanks, Cliff. Let's talk about CapEx a little bit. During 2007, we expect to spend approximately $193 million on development activities, $133 million for exploration, $27 million for seismic for a total of $353 million that will be capitalized. $31 million on expensed workovers and major maintenance projects and $37 million for plugging and abandonment. We also anticipate that we could spend between $15 million and $20 million in 2007 to repair damage to our facilities caused by Hurricanes Katrina and Rita. The timing of future repairs will be affected by equipment availability, design remediation planning, and finally, permitting. We anticipate drilling 15 exploratory wells and three development wells in 2007.

Now keep in mind that the Company has $275 million in mandatory debt services; we have said before we do not borrow money to drill with. I expect that as we have done in the past at midyear we will review our cash generation and reevaluate our CapEx budget for the remainder of 2007. Some of the analysts that follow our stock have already noted in their reports that we don't appear to have budgeted all the projected free cash flow. That is true. We see a plethora of opportunities in the Gulf right now, many known to the public and others that are not. We remain an opportunistic acquirer and cash flow is something we believe will allow us to capitalize on these opportunities.

As Danny discussed, in 2006 we spent $589 million on exploration development and seismic activities. This translates into a finding and development costs of $5.40 per Mcfe. As Jeff will discuss shortly, our three P additions for 2006 were approximately 374 Bcf equivalent, which should bring our F&D costs down to about $1.60 per Mcfe, which is another gauge of our success with the drill bit.

Now here is Jeff Durrant, our senior VP of exploration to review the fourth quarter 2006. He will discuss our 2006 drilling results and also detail our 2007 plans.

Thank you, Tracy. Good morning, everyone. As Tracy and others have already discussed, W&T's 2006 drilling program provided strong results. We drilled 19 successful exploration wells out of 26 for a 73% success rate and on top of that we were eight for eight in development drilling, for an overall drilling program success rate of 79%. While we had success in all three of the Gulf categories, our deep shelf exploration drilling programs stood out where we made discoveries on seven of the eight wells drilled.

Additionally we successfully drilled three out of six deepwater exploration wells and we were nine out of 12 on the conventional shelf. While we did have an excellent overall 2006 drilling program, there were 3 fourth-quarter exploration disappointments. We drilled 2 deepwater uneconomic wells, one of which was a 50% working interest Midway prospect in Alaminos Canyon 529 and the other was a 75% working interest well, the Dumont prospect, in Green Canyon 732.

Additionally our 100% working interest Ship Shoal 368 exploratory well was also uneconomic. The total cost for these 3 wells was about $53 million. For the fourth quarter on the conventional shelf, we did successfully drill the 83% working interest, Galveston 303 #7, where we found 57 feet of gas sand in 5 zones. First production from this well is expected in May of 2007.

While I believe our total 2006 drilling success of 79% is excellent, I believe the more important question is, what reserves were added and did we replace our production through the drill bit? Well, the answer is yes. The exploration program added a W&T Offshore record 109 Bcfe approved reserves in 2006. And as Cliff has previously reviewed including production from the Kerr-McGee properties, we produced a total of about 99 Bcfe and when compared with a 109 Bcfe of the reserve add, this results in 110% production replacement through the bit.

But just as significant are the probable and possible reserve additions from the 2006 exploration program. We added an additional 81 Bcfe probable reserves and another 183 Bcfe of possible reserves for a total three P case reserve addition of 374 Bcfe. The good news about the two P and the three P case reserves is that in many of our discoveries we thought our objectives structurally high and productive full to base. And as we bring these discoveries online, we will then be converting these probable and possible reserve to approved reserves in '07 and beyond with little or no additional capital expenditure.

Looking at 2007, so far we are off to a good start. We successfully drilled the 100% working interest B3 Sidetrack and High Island 22. This former Kerr-McGee property had a well that had shallower development objectives, along with a deeper exploration tail. Both portions of the well were successful, encountering about 40 feet of gas in five zones. The well has been completed and is currently producing 5.6 million cubic feet equivalents per day net to W&T. Additionally in the same general area, in High Island block 24 L, we are now drilling an exploratory offset to our 2006 Lentic Jeff discovery. We expect to finish drilling this 15,000 foot well in about 30 days.

Turning to our deepwater program, as planned, we reentered the Healey #3 well in Green Canyon 82 in order to finish drilling the well and evaluate the well's deeper objectives. You might recall that the drilling was temporarily suspended due to loop currents in the summer of 2006. Upon reentering this well in January, we drilled an additional 740 feet and found 45 feet of high-quality oil and gas sand in the well's main objective. Additionally we obtained 90 feet of conventional core in the 11,300 foot sand. This data along with results of a proposed Healey #4 well that we plan to drill later this year should allow us to finalize our development plans for this area. The Healey #4 well will test the down dip limit of the field's main reservoir along with three additional previously unpenetrated exploratory targets. This well is currently scheduled to begin drilling in September 2007, but it could spud as early as June.

The wells I just discussed are part of a proposed 2007, 15-well exploration program which includes at least two deepwater wells, three deep shelf and 10 conventional shelf wells. The unrisked potential for this program is about 325 Bcfe net to W&T. With fewer exploration wells planned for 2007, I would look for 2007 to be largely an information gathering year for many of the properties that were acquired in the Kerr-McGee transaction. Following the close of that transaction, we purchased a significant amount of 3-D seismic in order to provide a regional coverage over essentially all the former Kerr-McGee and W&T fields.

Using this new database we are actively evaluating the new Kerr-McGee fields as well as the existing W&T properties for exploration potential both in and around us, and so far what we have seen has been encouraging. Additionally as I am sure many of you are aware, this database will help us evaluate the exploration potential in three large upcoming OCS lease sales planned for August and October of 2007 and in March of 2008.

So in summary, our evaluation process in '07 should allow us to prepare for 2008 and beyond. With that I will pass it back to Tracy.

Thanks, Jeff. The next few years look to be a particularly active exploratory time as we grow our opportunity database and we capitalize on our extensive prospect inventory. Once again I would like to reiterate that we've had another outstanding year in operations and we had very good success with the drill bit. We continue to maintain our above-average record with drilling successes. Our drilling program has been successful for several years including 2006. Our success rate has had a trailing 12 month average of between 78% and 88% over the past two years. These rates are a lot more like those associated with onshore resource plays than those associated historically with the Gulf of Mexico. The key is we are generating the strong cash flow and targeting the higher potential projects as a Gulf of Mexico producer while also achieving what we think is a predictable and a steady success profile.

This year we will continue our focus on the integration of Kerr-McGee. Our teams are doing a great job of identifying new opportunities, increasing production and therefore cash flow. During our information gathering period, we will use our significant cash flows to repay the debt incurred in connection with the transaction and delever the company, as we've stated before. We are excited about our future drilling potential and look forward to continuing our track record of outstanding drilling success.

One other thing regarding Kerr-McGee. When I went into the dayroom to look at the package myself included we felt like we had bought about a Bcf equivalent not including 6 Bcf of unrisked and undrilled opportunities. That is a Bcf on the 3P case. That has not changed. We still think it is and we are very excited about this going forward.

Thanks to all the employees at W&T for their efforts in the past as we look to the future, and I guess that is about all I have to say today. That concludes our prepared remarks and we're ready to take your questions. Operator, please open the phone lines for Q&A.

(OPERATOR INSTRUCTIONS) David Adams.

David Adams, Jefferies and Company. Can you reconcile the 280 Bcfe for the Kerr-McGee properties midyear '06 versus the 200 and forty-something you booked in the reserve report? Is a significant amount of that differential, is it production between the time midyear and when you closed?

That's right, it is mostly production. It is mostly rolloff on the production. Remember we didn't gain control of the properties until October 1st of this year or excuse me -- of 2006, so yes, it is mainly runoff.

Okay, so it was booked as of October 1st, is that how it works?

No, actually it was booked at the end of the year as to what it was.

Okay, so the production in the reserve report does not include the Kerr-McGee properties?

It does. What we did was we did a midyear internal report in July and what you are seeing is affected the rolloff through the end of the year.

Okay, the next question I had you talked about the $1.87 3 P F&D case. If you were to incorporate future development costs with those properties, what would that take that to? Would it be mid-twos or even lower?

David, that is a question I can't really answer right now. We haven't gotten our hands around these properties yet as far as estimating future development costs. We have not even to this point recognized everything we're going to drill yet. So that is just a little bit premature. I would love to give you an answer but just can't do it right now.

Okay, I will hop back in the queue. Thanks.

Dell Monroe's. Tracy, obviously you all have a lot of stuff sitting in front of you to do next. Just wondering how active will you be in the lease block sale August or so or what we all focus on for the next year to two?

Neal, I expect that we will be pretty active. It's been a while since we've had some lease sales and again we bought a lot of data, so and we're still in this information gathering period, so I expect that we will be fairly active.

Okay, and then my follow-up as far as obviously you addressed the cost a little bit. I am just wondering for this year where do you all sit as far as infrastructure costs and your thoughts around that? Are you about where you want or is there still a fair amount that you have to add in the way of infrastructure?

I think we are pretty good on -- you're talking about personnel and that sort of thing?

That and just wondering for some of these other connections and stuff that you have, so a little bit of both.

I think we're in pretty good shape with regard to personnel and infrastructure. We are offshore and that sort of thing. If you are referring to deeper water things, we are continuing to assess where we go with some of these fields and particularly Green Canyon 82 we're still gathering data, that sort of thing. But we've got plenty of infrastructure particularly in and on the shelf.

Great, perfect. Thanks.

(OPERATOR INSTRUCTIONS) Brian Guzman.

JPMorgan. You have a history of positive reserve revisions. Could you go over why the revisions were negative this year?

Cliff, go ahead and answer that.

This is Cliff Williams. The negative its 13 Bcfe, we had the pricing impact was in the neighborhood of about 16 Bcfe, just pricing year-to-year. We had the oil price which stayed constant. On our SEC report the gas price was significantly lower. And then we had written off three PUDs, then offset by some positive revisions from our Mississippi Canyon 718, our Pluto Prospect better than expected performance there. So those are some of the reasons; but the pricing impact more than covered that 13 Bcfe of reduction.

I think if you run it on current pricing, I don't think we have -- I think it is pretty neutral, Brian.

Yes, current pricing you would add another about 9.5 Bcfe back to it.

To be very close to neutral.

And the cash tax payment you made in the fourth quarter I think was related to the hurricanes, where does that flow through the cash flow statement?

I am sorry, repeat the question Brian.

Yes, there was a cash tax payment you made in mid-October with regards to that Katrina relief act. I couldn't figure out where it flowed through the cash flow statement. It was like a $40.7 million --

That was a deferred tax cash payment because we had a lot of people in Metairie. As a result of the storms, the government allowed us to defer a cash tax payment, that was for 2005. It was deferred until October 2006. As far as where it flows through on the cash statement, I mean on the balance sheet, I would have to look at it to see. I don't have a great answer for you.

So it was a cash item that was paid in the fourth quarter?

It was a cash item for sure.

Okay.

[Kevin Wing]

(indiscernible) capital management. Sorry if I might have missed something during the call, but was there a DD&A guidance given for '07?

No, we did not give you DD&A guidance for '07.

Relative to what it was in Q4, what would we be looking for directionally?

Directionally I would think you would be looking for it to go down. I think the cost of goods and services and what not are going down. Things are getting back to a more rational position in the Gulf of Mexico, because much of the work has been done as a result of the damage caused by the storms.

Given the range you have given and the lease operating expenses for the full year, is that also the case? If you have better-than-expected experience in operating costs it is going to be at the lower end? What would take it to the higher end of the 167 to practically 200?

Well, that is a little bit of a nebulous question there. The reality is that probably if the cost of goods and services were to go up it would be tied directly to commodity prices going up as well. So you might see an increase in cost, but on a per Mcfe basis obviously you'd see hopefully a corresponding increase as well. So that would either be neutral or better on a per Mcfe basis if the price of commodities were to go up rapidly, because it takes several months for the cost of goods and services to catch up with commodity prices going up. The other portion of it is the insurance. We have settled our insurance and we think that remediating these costs going forward is like $15 million to $20 million for this coming year.

(OPERATOR INSTRUCTIONS) John White.

Natexis Bleichroeder. I was wondering do you think your reserve replacement ratio from the drill bit would've been better if you had been able to get control of the Kerr-McGee properties sooner? I know the closing was a little delayed by factors outside of your control.

I think probably on a general basis it would have been. The truth is that most of the stuff that we would be looking at to accelerate those would have been pretty low hanging fruit, workovers, through [tipping] recompletions, that sort of thing that could have affected us well, on a positive bases.

Okay, and a follow-up question, the probable and possible reserves you've talked about, the additions that is entirely or almost entirely from W&T operated properties prior to the Kerr-McGee acquisition?

That is correct.

Okay, thanks very much.

Brian Kuzma.

I'm still at JPMorgan, I hope. What were the PUD bookings associated with the Kerr-McGee properties you got?

I am sorry, I didn't hear the question.

What were the PUD bookings, the PUD bookings associated with the acquired reserves? You know what they were?

I don't have the exact number, but as I recall, generally a typical Gulf profile is about one-third, one-third, one-third. It may vary a few percentage points, but that's kind of what our profile is as well.

Okay, and then is there any discretion on the reserve booking side as to whether reserves can be booked towards revisions versus extensions? Or is that laid out by the SEC?

The SEC dictates how we do our reserve bookings for the ceiling tests for the PV-10 test. We do our reserve bookings according to definition.

But can they -- it seems like you could run into the situation where you say you've got some behind pipes stuff up hole that you could credit either towards extensions or towards revisions. Do you have that type of discretion or no?

Remember, all of our reserves are done by a third party. We give them the data and they do the reserves from the ground up, so it is not one of these things where we come in and we do the reserves and then somebody else comes in and blesses it for us. As far as up hole revisions versus extensions, yes, that could be affected if you had something else that was in that same reservoir that had a better-than-expected or worse than expected performance.

Okay, but you are 100% fully engineered, is that right?

Absolutely. Yes. We turn it over to Netherland and Sewell and they do our reserves for us. We certainly talk to them about it but at the end of the day it is their call as to what those proved reserves are.

Wonderful, thanks.

At this time we have no additional questions in the queue and I would like to turn the conference over to you for any closing remarks.

Again, the last thing is that I am really proud of this team. It has been a lot of activity over the particularly over the last year and the last two years since the hurricanes. This year we had a lot on our plate. We finished the Kerr-McGee transaction. We did a follow-on equity offering. We have finished the year with a 79% success rate with the drill bit. We got a new CFO. Let's see, what else? It was a very busy year for us. Oh, and of course we settled the insurance issue here just a few days ago, so it has been a busy time for us.

We have taken over operations at Kerr-McGee and I think that going forward we will have an outstanding success with this group of properties just like we have had with all of our acquisitions. And I would like to tell you that to my recollection I don't recall ever having done an acquisition that was not successful. That has been over twenty years, so we don't expect this to be any different. In fact we think this is a real homerun for us and it takes us a couple years after we get the properties in hand to have a significant increase in drilling activity. I don't expect this to be any different, and we're out looking for additional properties as we speak. We don't budget acquisitions, but we expect to have our fair share of them, so look for us in the future. We are going to have a good year this year and on into the future. Thanks so much.

Thank you, management. Ladies and gentlemen, at this time we will conclude today's teleconference. We thank you for your participation on the program. At this time you may now disconnect and please have a pleasant day.