W&T Offshore, Inc. (WTI) Q1 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the W&T Offshore's First Quarter Earnings Conference Call. [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 the 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 a recorded replay until May 16, 2012. To use the replay feature, call (303) 590-3030 and dial the passcode 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 a disclosure on forward-looking statements. Now I would like to turn the call over to Mr. Tracy Krohn, W&T's Chairman and CEO.

Thanks, Janet. Good morning to all. As always, we appreciate your interest in W&T and our first quarter 2012 earnings conference call. I have with me today are Jamie Vazquez, our President; Steve Schroeder, our Chief Operating Officer; and Danny Gibbons, our Chief Financial Officer. In a moment, Jamie and Steve will provide 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 or 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 a 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 7 more lenders to our existing bank facility and increased our borrowing base from $575 million to $650 million. This really is a bode 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 very active with many interesting assets available and it's likely to get better. Turmoil in commodity markets often creates excellent opportunities. As gas-heavy operators look to raise capital, offset decline in cash flow from dry gas projects, or other types of operators spread across through many basins refocus 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 whether they are onshore or offshore. With a large amount of cash flow, which is generated from or our offshore Gulf of Mexico properties coupled with our increased borrowing base and access to capital markets, we're all well -- we are very well positioned to move forward on our growth and value creation plan in 2012 and beyond. To facilitate that result, we've 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 paid a normal quarterly dividend that's continued to increase over time and was recently increased to $0.08 per share per quarter. And for the last 5 years, we've 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 were significant considering the low interest rate environment. Also if you'll recall, our total shareholder return, or TSR, for 2011 was 24.5%, which ranked us #1 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, as seen 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'll 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 strategy -- growth strategy. We focus on identifying properties in which we can make money, as well as where we can enhance the value of the assets using our many years of operating expertise. Offshore Gulf of Mexico. We have 2 active rig operations in progress. Currently, we are operating with 100% working interest, a rig on the Mississippi Canyon 243, A-4 side track well located in our Matterhorn field, which is a deepwater development well. This well has reached a total depth of 6,781 feet total vertical depth and we are currently completing a well in an oil sand that is expected to add 3,500 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 349 A-13 well located on the shelf in our Mahogany field. We just completed drilling A-13 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 A-13 well is expected to add 1,500 barrels of oil equivalent per day net, and net productions should come on at the end of May. The A-13 well is the third well of a potential 6-well drilling program that commenced in 2011 and will continue into 2013. Once we complete operations on the A-13 well, we plan to skid the rig and commence drilling of the A-5 side track 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 2 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 Gaines County. During the first quarter of 2012, operating 3 rigs, we completed 14 wells in Yellow Rose, 5 of which were exploratory and 9 were development wells. All 14 were vertical wells that each cost around $2 million net to drill and complete, targeting about 4,500 feet of vertical section in the Wolfberry. We anticipate that an average vertical well will yield at 26% IRR using 163,000 barrels of oil equivalent estimated ultimately covering Rose. 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 -- this will maintain -- we will maintain 3 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 5,600-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 on to the Terry County project. During the first quarter, we completed 4 exploration wells. As you know, Terry County is in 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 flowback 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 1 horizontal well in our Terry County project prior to announcing our future development plan. I would like to point out that we do not have any proved reserves booked related to this 9,500-acre area. So obviously, there's 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 6 counties in East Texas, which includes St. Augustine, Shelby, Jasper, Angelina, Nacogdoches and Sabine. As part of our initial exploration and delineation phase, which consists of a 4-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 a rig is moving off location and we are currently installing facilities. We expect to complete and frac this well in mid-June. After reviewing the initial results, we plan to drill 2 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 15 million barrels of oil equivalent, net of which has been booked as proved reserves to date. On these onshore areas, we'll continue to evaluate potential bolt-on acquisitions and increase our lease hold acreage position. Let's talk about the budget. Our capital budget for 2012, $425 million excluding acquisitions. Our plan 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 seismic -- and while development projects, seismic leasehold and other costs accounted for the 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 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 deepwater exploration well in 2012. Since that well is nonoperated, 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 firstly 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 downtime 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 in the continued strong Gulf Coast oil premium. During the first quarter, we completed a combined total of 39 workovers and recompletions. The total cost net to W&T during the first quarter was $9 million and resulted in a combined net production increase or net initial production rate of 2,260 barrels per day of oil equivalent. As in the past, we will continue to utilize a strong workover 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 3,060 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 29,200 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 million and 6.6 million barrels of oil between 2.0 million and 2.3 million barrels of natural gas liquids and between 54 and 60 Bcf of natural gas production. This will result in total production for the year to be between 16.9 million 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 projects 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. Let me start off with the discussion of revenue and pricing. Revenues for the first quarter were $235.9 million, presenting a 12% increase over the first quarter of 2011. We continue to benefit from higher oil prices and oil price premium that we realized on the sale of our Gulf Coast barrels. Our average realized sales price for oil $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 are most closely resemble Brent pricing which is trading at that significant premium to NYMEX pricing for WTI. Conversely, natural gas liquid 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% in 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 7,200 barrels per day over the first quarter of 2011. Let me move on to discussion of some of our expenses. Lease operating expenses, which include base LOE, insurance, workovers, maintenance on our facilities and hurricane or 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 number of properties covered. Facilities expenses were lower by $3.3 million as the 2011 period reflected work activities at certain fields but did not reoccur in the 2012 period. Workover costs were flat as the workover cost 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 to $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 on to 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 as it is between $75 million and $85 million. For the first quarter of 2012, our crude oil derivative loss was $39.6 million and it 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 the first quarter of 2012, $5.8 million of the loss was realized and $33.8 million was unrealized. Let me move on to a discussion of earnings. Net income for the first quarter of 2012 was $3.2 million or $0.04 a share compared to a net income of $18.6 million in 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 compares to $32.7 million or $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 lower 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 revolver capacity is now $650 million and we added 7 banks to our existing bank group as a part of the spring borrowing base redetermination. Accordingly, our liquidity continues to be strong and we continue to have strong support in the financial community. Both of these things will allow us to continue to pursue the growing list of acquisition opportunity to 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 approximates 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 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 extent 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 position 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's going to be plenty of opportunity this year. Operator, please open the door -- open the lines for questions.

[Operator Instructions] Our first question is from the line of Phil McPherson with Global Hunter Securities.

I had a few questions and I'll 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 to us, I guess, are these nonPUDs or things that weren't bookend and does that set up more PUDs kind of going forward?

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

And 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?

Not sure I have a great answer for that, Phil. I'd have to think about that a little bit.

That's fine. And I was just kind of curious on the -- Jamie, you went through the offshore stuff kind of quick. And on the A-13 Mahogany, I think you give us the cost on the Matterhorn but you didn't give us the cost on the Mahogany. I was wondering what the net -- or maybe the gross or the net cost on those wells are out there.

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

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

Yes. That's a litigation expense related to a lawsuit in Louisiana. And I believe that we've certainly recognized more than enough to cover it but I'm not going to comment on it other than to tell you that I think we've recognize more than enough to cover it.

The next question is from the line of Richard Tullis with Capital One Southcoast.

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

Yes, I believe we'll get it done this year, Richard. Right now, we're just waiting on a couple of items and I think one of those is in fact a permit. But I expect we'll spud here within the next 2 to 3 months.

Okay. And how much CapEx is in your 2012 budget related to this well?

Hold on just 1 minute, we'll get the number here for you. I'm 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'll jump back in the queue, how are the rig rates in general in the Gulf of Mexico trending?

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

The next question is from the line of Noel Parks with Ladenburg Thalmann.

Just a couple of things. Did I understand right that -- I'm just looking for the note here, the 3,500-barrel a day rate that you anticipate for Matterhorn, is that new? I thought I remembered the number being more like 20-some-hundred before like [indiscernible] something like that.

I think it's been the same, it's 3,500 is what we anticipate.

Okay. I may have had some net, gross confusion or something. And the other thing I wanted to ask you, let's see, sorry, I am 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, what -- 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 the lease explorations or are you avoiding your higher risk but higher return projects offshore because it looks like you have this growing inventory onshore?

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

The next question is from the line of Michael Glick with Johnson Rice.

Just had a quick question on horizontals is 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 the exploration potentially continuing into next year?

I think a little bit of both. I mean, we're getting ready to kick off our horizontal program out in West Texas. So these wells aren't going to take the rest of the year to drill, so we'll 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 in the Southeast of your acreage position targeting the Cline shale? Just wondering if you guys see any potential for the Cline on your position.

Yes. People -- and again, as you think about what the 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'm 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.

The next question is from a follow-up of the line of Phil McPherson with Global Hunter Securities.

Tracy, I just -- kind of a quick question. You're obviously generating way more cash flow than your spendings and so when you sit down and think about things -- the difference between acquiring more properties or accelerating what you're doing in the Permian, how do you kind of go through that thought process and 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're 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 positioned ourselves with quite a bit of liquidity and I feel pretty confident that that's going to prove to be a good thing for us.

And then taking that into context, if you didn't 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 really prevents us from that.

Okay, great. And jumping back to the offshore. On the Matterhorn, you talked about the Mahogany that it's the third of the 6 potential wells to do. At Matterhorn, what kind of inventory is left there to do 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 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'll finish drilling this round of wells, and then we'll take another look at it as we go forward. But big fields tend to get bigger, we keep finding reserves out here.

[Operator Instructions] The next question is a follow-up from the line of Richard Tullis with Capital One Southcoast.

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

Sure. We've got -- we're on the second horizontal well. We probably got a couple of more to drill before we'll 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's appropriate. Yes.

The next question is from the line of Dan McSpirit with 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's working from on 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 I'd take a little homework from you, Dan, figuring out what the value of our equity is. And we'll be happy to work with you on that.

The next question is a follow-up from the line of Michael Glick with Johnson Rice.

So just a quick question on the shelf. I think you guys had planned 5 exploration wells in the shelf this year. Just kind of wondering where that program stands, and what the timing is associated with it.

I'm sorry, would you repeat the question?

I think you guys had planned 5 exploration wells on the shelf this year. I'm just curious where the program stands.

Let's see. I think we're through well #3 now, exploratory.

We have a couple of wells in -- scheduled to spud -- set late second quarter, early third quarter. And then 2 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 that's the schedule.

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.