W&T Offshore Inc (WTI) 2012 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 participants 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, Wednesday, May 9, 2012.

I would now like to turn the conference over to Janet Yang, Manager of Finance. Please go ahead.

Thank you operator, and good morning everyone. We appreciate you joining us for W&T Offshore's conference call to review the results of first quarter of 2012. 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 16, 2012. To use the replay feature, call 303-590-3030 and dial the pass code 4532663, followed by the pound sign. Information recorded on this call speaks only as of today, May 9, 2012 and therefore time sensitive information may no longer be accurate as of the date of any replay. Please refer to our first quarter 2012 earnings release for 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, you all. As always, we appreciate your interest in W&T and our first quarter 2012 earnings conference call. I have with me today Jamie Vazquez, our President; Steve Schroeder, our Chief Operating Officer; and Danny Gibbons, our Chief Financial Officer. In a moment, Jamie and Steve will provided a review of our first quarter operating activity and guidance, and then Danny will go over some of the financial highlights for the quarter. The first quarter clearly demonstrates many of the Company's strengths, such as the Company's ability to generate significant cash from our Gulf of Mexico assets.

Our oil production receives premium pricing there. In the first quarter our adjusted EBITDA, which is a measure of cash flow, was $146.5 million, and was driven by our substantial production of oil and natural gas liquids. In fact, in the first quarter of 2012, about 83% of our total revenues were from oil and NGLs. We use our strong cash flow to fund our drilling activity. That means that we don't borrow money to drill with. Second, the Company has an outstanding liquidity position. We just recently added seven more lenders to our existing bank facility and increased our borrowing base from $575 million to $650 million.

This really is a vote of confidence from our banks. We have excellent support, and we expect to use the available capital to fund acquisitions and/or development projects. The market is active with many interesting assets available, and it is likely to get better. Turmoil in commodity markets often creates excellent opportunities, as gas heavy operators look to raise capital, offset declining cash flow from dry gas projects, or other types of operators spread across too many basins, we focus their strategies. We think the M&A markets will get even more active. W&T is an established buyer of both larger and smaller opportunities, regardless of whether they are onshore or offshore.

With a large amount of cash flow which is generated from our offshore Gulf of Mexico properties, coupled with our increased borrowing base and access to capital markets, we are very well positioned to move forward on our growth and value creation plan in 2012 and beyond. To facilitate that result, we have carefully structured our incentive compensation plans so that all of our employees understand these objectives and are aligned with our goals. Next, as you know, we always align ourselves with our shareholders with a focus on total shareholder returns, which includes dividends. We have paid a normal quarterly dividend that's continued to increase over time, and was recently increased to $0.08 per share per quarter. In four of the last five years we have also paid a special dividend that has been substantial. Our dividend yield of 3.7% for 2011 was the highest in our peer group, whose average yield was close to 0%, and was significant when considering the low interest rate environment. Also, if you will recall, our total shareholder return, or DSR, for 2011 was 24.5%, which ranked us number one among a list of 19 peer group companies, a fact that we're very proud of.

We believe that our shareholders should share in the Company's success by seeing great returns on their investment over time. We continue to recite that the Gulf of Mexico has enormous opportunities for future exploration and development, and we intend to continue to take advantage of that using our offshore operating expertise that spans over 28 years. Simultaneously, we will also continue to pursue onshore exploration and development opportunities, including our current projects in the Permian Basin of West Texas with its multiple pay zones, and our James Lime opportunity in East Texas. Currently nearly half of our production is oil and NGLs, and we expect this percentage to increase as our 2012 drilling program is brought online. Our drilling dollars are focused mostly on oil and liquids rich gas projects, but our acquisition activities are more general, and focused on full cycle economics.

So with that, let me turn the call over to Jamie for an operations update.

Thank you, Tracy. We are working to achieve our growth objective with a balanced approach. We expect to achieve both reserve and production growth in 2012 from our exploration and production activities, and through acquisitions. We continue to have great success with the drill bit. So far in 2012, we have a success rate of 100% on the 18 completed wells located onshore, of which 9 were exploration wells. Historically, W&T has made accretive acquisitions which have played a major role in our growth strategy. We focus on identifying properties in which we can make money, as well as where we can enhance the value of the asset using our many years of operating expertise.

Offshore Gulf of Mexico, we have two active rig operations in progress. Currently we are operating, with 100% working interest, a rig on the Mississippi Canyon, 243A4 sidetrack well, located in our Matterhorn Field, which is a deep water development well. This well has reached a total depth of 6781 feet total vertical depth, and we are currently completing the well in an oil span that is expected to add 3500 barrels of oil equivalent per day net to our interest in mid-June. The estimated cost to drill and complete this well is $35 million net, which provides an IRR in excess of 100%. Since acquiring the Matterhorn Field in the spring of 2010, we have increased production by an impressive 54%.

Our second operated rig is conducting operations on the Ship Shoal 349A13 well, located on the shelf in our Mahogany Field. We just completed drilling the A13 development well to a total depth of 15,343 feet, and we are currently completing the well in the P Sand where we found a net 106 feet of oil pay. The A13 well is expected to add 1500 barrels of oil equivalence per day net, and that production should come on at the end of May. The A13 well is the third well of a potential six-well drilling program that commenced in 2011 and will continue into 2013. Once we complete operations on the A13 well, we plan to skid the rig and commence drilling of the A5 sidetrack in late May, which is a development well also targeting oil in the P Sand. This program is expected to yield an IRR of excess of 100%. Mahogany is our largest offshore field and is owned 100% by W&T.

Onshore, we have ongoing operations in two focus areas in Texas. One area of focus is in the Permian Basin, where we have approximately 32,000 net acres under lease and are actively exploring and developing our Yellow Rose and Terry County projects. The other area of focus is East Texas where we have approximately 142,000 net acres under lease, which we refer to as our Star Project. In the Yellow Rose project in West Texas, we have 22,900 net acres under lease, located in Dawson, Martin, Andrews and Gains county. During the first quarter of 2012, operating three rigs, we completed 14 wells in Yellow Rose, 5 of which were exploratory and 9 were development wells. All 14 were vertical wells. They each cost around $2 million net to drill and complete, targeting about 4500 feet of vertical section in the Wolfberry.

We anticipate that an average vertical well will yield a 26% IRR using 163,000 barrels of oil equivalent estimated ultimate recovery gross. The field is currently booked on 80-acre spacing. However, we expect to move to 40-acre spacing, and possibly 20-acre spacing in the future. It is anticipated that we will maintain three rigs throughout 2012, and that the development drilling program will continue into 2015. In June 2012 we plan to begin our pilot test horizontal program with the drilling of our first horizontal well in Yellow Rose, targeting the upper Wolfcamp with a 5600-foot lateral, with an initial estimated cost of $6.9 million to drill and complete. The Yellow Rose Field has huge upside, with the potential of both down-spacing and the horizontal development.

Moving onto the Terry County project, during the first quarter we completed four exploration wells. As you know, Terry County is a Wolfberry play. Since 2011 we have completed a total of 10 vertical wells, drilling to about 12,000 feet at a cost of $2.3 million to drill and complete for each well. We are currently in our exploration and delineation phase in this area, and the wells we drill today are at various stages in completion and flow-back, and we will continue to analyze this data that we receive from these wells. As a part of our delineation plan, we anticipate drilling at least one horizontal well in our Terry County project prior to announcing our future development plans. I would like to point out that we do not have any proved reserves booked related to this 9500-acre area, so obviously there is upside opportunity for reserve and production growth in 2012 and beyond.

Moving to East Texas, we have active drilling operations in our Star Project. Star Project covers six counties in East Texas, which include St. Augustine, Shelby, Jasper, Angelina, Nacogdoches, and Sabine. As part of our initial exploration and delineation phase, which consists of a four-well program in 2012, we have drilled our second horizontal well to total measured depth of 13,976 feet, targeting the James Lime formation. We have set casing, and the rig is moving off location, and we are currently installing facilities. We expect to complete a practice well in mid-June. After reviewing the initial results, we plan to drill two additional horizontal wells in 2012, which should provide sufficient data to determine future development plans. The estimated cost per well is $6.4 million, with a targeted IP rate of 833 barrels of oil equivalent per day gross. If successful, we estimate that this project could yield 50 million barrels of oil equivalent, none of which has been booked as proved reserves to date. On these onshore, areas we will continue to evaluate potential bolt-on acquisitions and increase our leasehold acreage position.

Let's talk about the budget. Our capital budget for 2012, $425 million, excluding acquisitions. Our planned drilling program is currently progressing according to our schedule. During the first quarter of 2012, our oil and gas capital expenditures were $84.6 million, which included $46.4 million for onshore activities and $33.4 million for offshore activities, with another $4.8 million for seismic, leasehold, and other costs. Our exploration projects accounted for 20%, while development projects, seismic, leasehold, and other costs accounted for remaining 80%. We are still targeting to drill 10 offshore wells and 65 onshore wells with an investment of about $167 million for exploration activities and $258 million for development activities. Most of all, all the budget is directed at oil and liquids rich projects. It should be noted that W&T has historically drilled within cash flow, and most of the time has operated completely within cash flow. We plan to participate with a 20% interest in a deep water exploration well in 2012. Since that well is non-operated, we are not in control of the timing. However, we view this well as a strong exploration project which could have significant impact on the Company if successful. We plan to provide more details about that well as we approach the spud date.

With that, I will turn the call over to Steve Schroeder to update you on some other operational items.

Thanks, Jamie. 2012 is off to a good start, with our first quarter daily production averaging 49,200 barrels of oil equivalent per day, as compared to about 42,000 barrels of oil equivalent per day in the first quarter of 2011, in spite of unscheduled down time associated with pipeline outages and new facilities installations. This is a 17% increase over the first quarter of 2011, with 47% of the production coming from oil and natural gas liquids. We expect to maintain solid production rates from our properties as we bring on additional wells at Mahogany and Matterhorn during the second and third quarters. These oil rich development targets, coupled with continued growth onshore, should help us continue to grow production this year, while at the same time take advantage of oil prices and the continued strong Gulf Coast oil premium. During the first quarter we completed a combined total of 39 work-overs and recompletion's. The total cost net to W&T during the first quarter was $9 million, and resulted in a combined net initial production rate of 2260 barrels per day of oil equivalent. As in the past, we will continue to utilize a strong work-over and recompletion program throughout the year to maintain our production.

Moving to our onshore operations, at our Yellow Rose properties in the Permian Basin we continue to see efficiencies, such as reducing our overall drilling time, and have been averaging between 15 and 16 days of drilling time on a spud-to-spud basis. We are currently producing around 3060 barrels of oil equivalent per day gross. It is our goal to increase production over 2011 by 5% or more -- 5% or more in 2012. As you know, we produced 49,200 barrels of oil equivalent per day in the first quarter. During the month of April, production from certain fields was affected by outages of a third-party pipeline that reduced April production to around 47,700 barrels per day, before normal recurring adjustments. That pipeline has since returned to service, and our production has been restored, and we are currently producing right around 49,800 barrels of oil equivalent per day. Regardless, we are reaffirming our prior full year 2012 guidance of between 5.9 and 6.6 million barrels of oil, between 2.0 and 2.3 million barrels of natural gas liquids, and between 54 and 60BCF of natural gas production. This will result in total production for the year to be between 16.9 and 18.8 million barrels of oil equivalent, or 101.1 and 112.9 Bcfe. This guidance continues to include some downtime for hurricanes, similar to what we experienced in 2011.

Relative to lease operating expenses, LOE for the first quarter increased on a nominal basis, due to expanded operations associated with our acquisitions completed in 2011, but on a per Boe basis, lease operating expenses decreased to $12.65 per barrel from $13.85 per barrel in the first quarter in 2011. We are beginning to see increased production handling agreement fees from our compressor project at Main Pass 252, and late this quarter should see between $500,000 and $1.5 million per month in fees from the recent third-party tie-back to our Matterhorn facility. Together, these should provide a nice offset to some of the increases that affected the first quarter LOE, along with our typically higher expenditures during the summer months. As a result, our guidance for lease operating expense for 2012 remains unchanged from prior guidance, and is between $215 million and $237 million. Our guidance for gathering transportation and production taxes for 2012 remains unchanged, and is between $25 million and $35 million. Production taxes are expected to be higher in 2012 compared to 2011, with the increased production in Texas and Alabama.

Now let me turn the call over to Danny. Danny?

Thank you, Steve. We start off with a discussion of revenue and pricing. Revenues for the first quarter were $235.9 million, representing a 12% increase over the first quarter of 2011. We continue to benefit from higher oil prices and oil price premium that we realize on the sale of our Gulf Coast barrels. Our average realized sales price for oil was $110.39 per barrel, a $12.49 per barrel increase over the 2011 period. Keep in mind that about 85% of our oil is priced on the Gulf Coast, where prices more closely resemble Brent pricing, which is trading at a significant premium to NYMEX prices for WTI. Conversely, natural gas liquids prices decreased $1.63 per barrel during the quarter to $48.51, and the relationship to our realized crude price declined to 44%. In addition, natural gas prices dropped $1.62 per MCF to $2.67 per MCF in the quarter. As a result, our average realized sales price was $52.41 per barrel of oil equivalent, or $8.74 per Mcfe in the first quarter of 2012, and that's down about 5.8% from the first quarter of 2011. Contributing to higher revenues during the quarter was higher production volumes, which were up for all the products that we sell. In fact, our production averaged over 49,200 barrels of oil equivalent per day, which is up 7200 barrels per day over the first quarter of 2011.

Let me move onto a discussion of some of our expenses. Lease operating expenses, which include base LOE, insurance, work-overs, maintenance on our facilities, and hurricane remediation costs net of insurance claims increased $4.3 million to $56.7 million in the first quarter of 2012, compared to the first quarter of 2011. On a per barrel of equivalent basis, LOE decreased to $12.65 per Boe during the first quarter of 2012, compared to $13.85 per Boe during the comparable 2011 period. Base LOE increased $6.8 million, primarily as a result of acquisition activity in 2011. Insurance premiums are up $1.9 million, and reflect an increase in the properties covered. Facilities expenses were lower by $3.3 million, as the 2011 period reflected work activity at certain fields that did not reoccur in the 2012 period. Work-over costs were flat, as the work-over costs incurred for our onshore operations were offset by a decrease in our offshore activities. DD&A, including accretion for ARO, increased to $19.75 per barrel of oil equivalent for the first quarter of 2012, from $19.58 per Boe in the first quarter of 2011. On a nominal basis, DD&A increased $88.5 million for the first quarter of 2012 from $74.1 million in the first quarter of last year. DD&A on a nominal basis increased primarily due to higher production volumes.

Moving onto general administrative expenses, they increased to $29.5 million for the first quarter of 2012 from $18.1 million for the first quarter of last year. It's primarily due to an $8.3 million litigation accrual and expanded activities onshore and offshore. G&A on a per barrel basis was $6.58 for the first quarter of 2012, compared to $4.79 for the same period in 2011. Our guidance for G&A expenses for the year 2012 remains unchanged, and is between $75 million and $85 million. For the first quarter of 2012, our crude oil derivative loss was $39.6 million, and relates to the change in the fair value of our crude oil commodity derivatives as a result of increases in crude oil prices relative to the contract prices. Although the contracts relate to production for the current and future years, changes in the fair value for all open contracts are recorded currently. For this first quarter of 2012, $5.8 million of the loss was realized and $33.8 million was unrealized.

Let me move onto a discussion of earnings. Net income for the first quarter of 2012 was $3.2 million, or $0.04 a share, compared to net income of $18.6 million and earnings per share of $0.25. Net income for the first quarter of 2012 excluding special items was $30.6 million, or $0.40 a share. The special items included a litigation accrual and an unrealized derivative loss. Please note that this compares to $32.7 million, or $0.$0.43 a share reported for the first quarter of 2011, excluding special items which also included an unrealized derivative loss. For the first quarter of 2012, adjusted EBITDA was $146.5 million, an increase of 10% compared to $133.3 million for the first quarter of 2011. Net cash provided by operating activities for the first quarter of 2012 was $128.2 million, an increase over the $72.7 million reported for the same period of the prior year. Adjusted EBITDA and cash flows from operating activities increased, due to higher realized oil prices and higher production volumes, partially offset by higher cost.

Cash flow was more than sufficient to fund capital expenditures of $85.1 million, pay dividends of $5.9 million, and still reduce long-term debt by $33 million. Our cash balance as of April 24, 2012 was $36 million, and we had $72 million drawn under the revolver. Our borrowing base and revolver capacity is now $650 million, and we added seven banks to our existing bank group as part of the spring borrowing base redetermination. Accordingly, our liquidity continues to be strong and we continue to have strong support from the financial community. Both of these things will allow us to continue to pursue the growing list of acquisition opportunities, both offshore and onshore.

Talk about income taxes for a moment. Income tax expense decreased to $2 million for the first quarter of 2012, compared to $10.2 million for the same period of 2011. The decrease is primarily attributable to the change in pretax income. Our effective tax rate for the first quarter of 2012 and 2011 was 38.1% and 35.3%, respectively, both of which approximate the statutory rate. We made a $10 million tax payment during the first quarter, and expect that any future tax payments for 2012 will be related to alternative minimum tax, and will not be significant. For 2012 our effective tax rate is expected to be around 38.1%, due to a combination of the federal statutory rate, state taxes related to our West Texas production, and Alabama state taxes due to our Fairway production.

Talking about hedges, a summary of our commodity derivative positions can be found at the Investor Relations Section of our website. No new positions were entered into since the end of the first quarter. During the first quarter of 2012, we paid a regular cash dividend of $0.08 per share, which represents an increase of 100% over the $0.04 per common share per quarter that we have been paying over the last few years. We anticipate funding our 2012 capital budget and acquisitions with internally generated cash flow, cash on hand, borrowings under our revolving bank credit facility, and accessing the capital markets to the extend necessary. With that, I will now turn the call back over to Tracy for closing comments.

Thanks, Danny. We continue to believe that 2012 will be another great year for us with both the drill bit and acquisitions. We have positioned the Company to maintain strong liquidity and to continue to generate positive cash flow, largely as a result of not borrowing money to drill. As a result, we can move strongly and decisively when opportunity knocks at the door. We think there is going to be plenty of opportunity this year.

Operator, please open the lines for questions.

Thank you.

(Operator Instructions)

We do ask that you please limit yourself to one question and one follow-up, then re-queue for any additional.

Phil McPherson, Global Hunter Securities.

Nice job. I had a few questions, and I will queue back in for some other ones, but I was just curious on your definition of development versus exploration in the Yellow Rose area. The 14 wells all look good, and then I guess 5 of them were exploratory. So could you explain us, I guess are these non-PUDs or things that were not booked, and does that set up more PUDs kind of going forward?

Yes and yes. That is exactly what it does. They are on acreage that is not booked as PUDs, and then as we drill that acreage, we very often will prove up additional acreage.

Of the acreage out there, what's the split between what's booked and what's not booked, or how do we think about that from an inventory perspective?

I am not sure I have a great answer for that, Phil. I would have to think about that a little bit.

Okay.

Yes, go ahead.

That is fine, and I was kind of curious on the -- Jamie, you went through the offshore stuff kind of quick, and on the A13 Mahogany, I think you gave us the costs on the Matterhorn but you did not give us the costs on the Mahogany. I was wondering what the net, or maybe the gross for the net costs on those wells are out there.

It is about $21 million to drill the well, and $5 million or $6 million to complete it.

I will queue back in. I just wanted one more quick question. On that litigation expense, what was that litigation and why was it kind of a surprise to us for the quarter?

Yes. That is a litigation expense related to a lawsuit in Louisiana, and I believe that we have certainly recognized more than enough to cover it, but I am not going to comment on it, other than to tell you that I think we have recognized more than enough to cover it.

Richard Tullis, Capital One Southcoast.

Tracy, I know you are not in a position at this time to give too many details on the potential deep water exploration well, but what still needs to be lined up to get the well spud this year? Is the rig set up, all permits?

Yes, I believe we will get it done this year, Richard. Right now we are just waiting on a couple of items, and I think one of those is, in fact, the permit, but I expect we will spud here within the next two to three months.

Okay, and how much CapEx is in your 2012 budget related to this well?

Hold on just a minute. We will get the number here for you.

Sure.

I am going to say around $20 million to $25 million, just off the top of my head here.

Okay, and then lastly for me, and I will jump back in the queue, how are the rig rates in general in the Gulf of Mexico trending?

I think right now they are pretty sideways.

Okay.

They jumped up a little bit in the first part of the year, which they normally do as we head into the summer season, because activity picks up, but I am not seeing any other increases at this point in time. I am not necessarily seeing any decreases. I just call it sideways.

Noel Parks, Ladenburg Thalmann.

Just a couple of things. Did I understand right that, on my note here, the 3500 barrel a day rig that you anticipated for Matterhorn, is that new? I thought I remember the number being more like 2000-some before, 2700, something like that.

I think it has been the same. It is 3500 is what we anticipate.

Okay. I may have had some net gross confusion or something. The other thing I wanted to ask you, let's see -- sorry. Getting my notes a little bit shuffled up here. Looking at your inventory in the Gulf, and as you sort of weigh it against, or as you high grade it and weigh it against the onshore opportunities, has the move onshore sort of changed your priorities regarding the offshore in terms of, I don't know, maybe onshore being a priority, just because of lease explorations, or are you avoiding your higher risk but higher return projects offshore, because it looks like you have this growing inventory onshore?

Yes. Let me answer that with the idea that we are constantly reevaluating our portfolio. That is something we do on just about a daily basis. I would tell you that with regard to onshore, certainly that is a lower rate of return on a per well basis, but very substantial reserves as well. The offshore stuff that we see and that we are drilling is very high cash flow, which we have done for many years. So no real change in philosophy here. It is still all about full cycle economics, and that is really what we are trying to assure ourselves in both areas, is that onshore that we do this in a manner that is befitting full cycle economics. Different way, we are still not going to borrow money to drill with. Okay?

Great. Thanks a lot.

Michael Glick, Johnson Rice.

Just had a quick question on horizontals in the Permian. Is it fair to look at 2012 as kind of exploration mode with a potential shifting into development mode in 2013, or should we look at exploration potentially continuing into next year?

Well, I think a little bit of both. I mean, we are getting ready to kick off our horizontal program out in West Texas. So these wells are not going to take the rest of the year to drill. So we will start looking at it and figuring out what we have, and then 2013 will certainly be a more definitive year.

Okay, and then I think some other operators had success kind of to the southeast of your acreage position targeting the Cline Shale. I was just wondering if you guys see any potential for the Cline on your position?

Yes, people, again, as you think about what these different formations are called, different operators call them different things. So a Cline Shale may in fact be a Wolfcamp formation in different areas of this basin. So I am not sure if I can really give you a fair answer on that without being able to sit down with the logs and compare them.

Phil McPherson, Global Hunter Securities.

Thanks. Tracy, I just have kind of a quick question. You are obviously generating way more cash flow than you are spending, and so when you sit down and think about things, the difference between acquiring more properties or accelerating what you do in the Permian, how do you go through thought process? Is there anything kind of holding you back in the West Texas part to add more rigs?

No. The consideration is opportunistic. Clearly, we think that this year is an opportunity year for acquisitions. I mean, prices are bouncing around, and we are seeing some other operators that did things a little bit different from us in the way of managing their cash flow that are going to need to be selling assets. We have positioned ourselves with quite a bit of liquidity, and I feel pretty confident that is going to prove to be a good thing for us.

Taking that into context, if you did not acquire something, is there anything from a logistics standpoint in West Texas from you doubling your rig count in 2013 if you wanted to?

No, nothing that really prevents us from that.

Okay, great. And jumping back to the offshore. On the Matterhorn, you talked about at Mahogany that it is a third of the six potential wells that do. At Matterhorn, what kind of inventory is left there to drill?

We continue to find more inventory out there as we get better data. This latest round of drilling was generated off of some better data, more data that we have purchased and reprocessed, and also some additional field study that we did with reservoir simulation. It's been 100% successful so far. So we feel pretty good, and we will finish drilling this round of wells, and then we will take another look at it as we go forward, but big fields tend to get bigger. We keep finding reserves out here.

(Operator Instructions)

Richard Tullis, Capital One Southcoast.

Yes. Tracy, just to verify the potential time line for announcing the initial results for the Star Project in Terry County, could you go over that again, please?

Sure. We are on the second horizontal well. We have probably got a couple more to drill before we will have anything really definitive for the markets. So I would look to hear more definition toward the end of the year on this.

Okay, and that would be both of those at the same time, both of those project areas?

Yes, I think that is appropriate, yes.

Dan McSpirit, BMO Capital Markets.

Your decision to move onshore and to further diversify the asset base certainly appears to be working from an operational and a financial point of view, but do you think it is working from an equity valuation point of view, and if not, what do you think it takes to get recognized for that hybrid model to be better recognized and to generate multiple expansion?

I think it would take a little homework from you, Dan, figuring out what the value of our equity is.

Right.

And we will be happy to work with you on that.

Michael Glick, Johnson Rice.

Just a quick question on the shelf. I think you guys had planned five exploration wells on the shelf this year. Just kind of wondering where that program stands and what the timing is associated with it?

I am sorry. Would you repeat the question?

I think you guys had planned five exploration wells on the shelf this year. Just curious where that program stands?

Let's see. I think we are through well number three now, exploratory.

We have a couple of wells scheduled to spud in late second quarter, early third quarter, and then two more at the end of the year in the fourth quarter, with the current schedule. Several of those are nonoperated so we are not in complete control of it, but all indications are that is the schedule.

Thank you. There are no further questions at this time. I will turn the conference back over to Mr. Krohn for any closing remarks.

Okay, thank you very much. I appreciate it. We will talk to you next quarter.

Ladies and gentlemen, this does conclude the conference call. If you would like to listen to a replay of today's conference, please dial 303-590-3030 and enter in the access code of 4532663. Thank you for your participation. You may now disconnect.