W&T Offshore Inc (WTI) 2009 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the W&T Offshore fourth quarter 2009 earnings conference call. (Operator Instructions) I would now like to turn the call over to Janet Yang, Finance Manager with W&T Offshore.

We appreciate you joining us for W&T Offshore's conference call to review the fourth quarter 2009 results. Before I turn the call over, I have a few items to go over. If you would like to be on the Company's e-mail distribution list to receive future news releases, or you experienced a technical problem and didn't receive yours, please call DRG&E's office at 713-529-6600 and someone will be glad to help you. 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 March 4, 2010. To use the replay feature, call 303-590-3030 and dial the pass code 4206518.

Information recorded on this call speaks only as of today, February 25, 2010, and therefore time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our fourth quarter 2009 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. I'm glad I made you memorize that. Good morning, everyone. Thanks for joining us on this conference call. With me today are Danny Gibbons, our Chief Financial Officer; and Steve Schroeder, our Chief Operating Officer; also Jamie Vazquez, our President and Jeff Durrant, our Senior VP of Exploration. They're all going to be here for the Q&A session.

Today, we're going to review the significant events that took place in the fourth quarter and full year 2009 and also discuss our outlook for 2010. During the past year, in the face of market uncertainty, and low commodity prices, we focused on strengthening the Company to assure a longer-term success. Some of our objectives aim to reduce operating costs, overhead expenses, long-term debt, and asset retirement obligations. We also wanted to preserve our borrowing base, partially by the incorporation of a new hedging program into our process and reducing our abandonment liabilities. We also sought to maintain good liquidity, sustain our dividend to shareholders and avoid raising expensive or diluted capital. We achieved all of those goals and the Company returned to profitability and achieve EBITDA margins more in line with historical levels.

Additionally, we put significant time and effort into developing profitability initiatives, reorganizing and enhancing certain departments, increasing our prospect inventory, selling non-core assets, reevaluating deep water projects, and evaluating new basins, that's with an S, for potential acquisition. Specifically we increased our prospect inventory to 160 prospects, which included conventional shelf, deep shelf, deep water, high impact, low impact, low risk, higher risk, subsalt, deep water subsalt, in the Gulf of Mexico, as well as some projects onshore Gulf Coast region. Furthermore, we sold non-core assets in two divestiture sales, which significantly reduced future expenses and obligations. However, we did retain upside by keeping the right to participate with half of our interest in the deep projects and/or identified prospects on some of the fields we've divested. As a result of these actions, we're entering this next decade with expanded strategies for increasing reserves and production.

Let's talk about the budget a bit -- 2009 budget. In 2009, capital expenditures were $276.1 million, consisting of $90.6 million for exploration, and $162.1 million for development activities, and $23.4 million for seismic, capitalized interest, and other lease hold costs. During the year, we focused on meeting drilling obligations, securing leases, placing our Daniel Boone project on production and performing recompletes to limit our capital expenditures and maintain steady production levels. We drilled 13 wells and achieved an overall success rate of 77%. We also performed 28 recompletes with excellent results, but as we expected, based on our limited capital program, this activity couldn't replace the high level of production Gulf of Mexico wells generate.

We'll talk about reserves a little bit. At December 31, 2009, our proved reserves were 371 billion cubic feet equivalent, or Bcfe, compared to 491.1 Bcfe equivalent at December 31, 2008. We also had 140 Bcfe of probable and 406 Bcfe of possible reserves based on new SEC guidelines. The ratio of oil and liquids versus natural gas remained at a high of 55% of proved reserves. The 120 Bcf decline in proved reserves between years reflects production for the year of 94.8 Bcfe and other net reductions of 24.4 Bcfe. So the new SEC rules definitely contributed to the majority of those net reductions in a couple of different ways.

First, the new rules limited the time that proved undeveloped reserves may remain in the proved reserve category to five years. We had two fields, both nonoperating, that were impacted, and a total of 23.2 Bcfe of reserves were de-booked. Second, the change in the price deck from end of year prices to a rolling 12-month average had the affect of reducing reserves another 25 Bcf and our PV-10 by about $670 million. The PV-10 of our total proved reserves is $890 million at the new average pricing, and includes new estimated asset retirement obligations. Netherland, Sewell and Associates -- NSAI -- our third party petroleum consultant evaluates and calculates our reserves from the ground up. This means they perform an independent engineering and geologic assessment of all of our reserves. We give them the data. They figure out what the answer is from the data that's supplied to them.

To quantify the effect of the new SEC methodology on our reserves, we asked NSAI to prepare estimates of our year-end proved reserves by applying the previous SEC pricing methodology of using just oil and natural gas prices at December 31, 2009. Based on that methodology, our PV-10 value would have been substantially higher. In fact, it would have been 80% higher, at approximately $1.6 billion and proved reserves would have been 396 Bcfe. Note that those reserves haven't gone anywhere. They are still in the ground. This is a pricing issue.

You may have noted that in our earnings release, we provided a comparison of estimated proved reserves based on the new SEC pricing method to the December 31, 2009, flat price, as well as comparison to a NYMEX case, which is based on the forward closing prices on the New York Mercantile Exchange for oil and natural gas as of December 31, 2009. In the NYMEX case, proved reserves were 406 Bcfe and PV-10 was $1.8 billion, or more than twice as high as the new case. Also, keep in mind that the two divestitures reduced reserves by another 24 Bcfe. Offsetting these reductions were discoveries and extensions of 23.4 Bcfe. Successful programs at Main Pass-108 and Main Pass-283 accounted for 66% of our 2009 extensions and discoveries. So for 2010, our total capital expenditures budget, CapEx, is $450 million, and we expect to fund that with internally generated cash flow and cash on hand.

Earlier, we announced that the budget included seven conventional shelf exploration wells and other capital items such as well recompletes, facilities capital seismic and lease hold items. We recently added three wells to the plan and continue to evaluate the expected costs associated with the original seven wells. Our plan now includes 10 wells, plus the other capital items budgeted at $153 million. The balance of the $450 million budget will be allocated to acquisitions, additional drilling opportunities from the Company's prospect inventory and/or new joint ventures offshore on the shelf or in the deep water, as well as onshore. In 2010, and over the next few years, we intend to conduct more high impact projects, complete acquisitions more frequently, pursue onshore projects, and refocus on deep water opportunities, both within our prospect inventory, as well as through joint ventures.

Admittedly, one of our biggest challenges of late has been to create a program that generates growth and production reserves year after year. We've always done a great job of generating cash flow. But we need -- we know we need to do a better job of balancing that with reserve growth. As a 26-year-old Company, we've been through many boom and bust cycles. We know that during these so-called bust cycles, we also have a tendency to have growth spurts. So similar to the past, we see this cycle as a growth opportunity for W&T. Having said all of that, I'll turn it over to Danny to discuss some of the financial items.

Thanks, Tracy, and good morning, everyone. Today I'll go over some income statement highlights, our cash balance and liquidity, and movements at our plug and abandonment liabilities, among other topics. As we've done throughout 2009, I'm going to make a sequential comparison rather than year-over-year comparison of our quarterly financial performance, given the considerable difference between 2009 and 2008 in terms of operations. For year-over-year comparisons of our quarterly financials, please refer to our press release. Revenue increased 5% to $176.1 million in the fourth quarter of 2009 from $167 million in the third quarter, driven by higher average realized sales prices per Mcfe, partially offset by lower production volumes.

Our average realized sales price increased 22% to $7.67 per Mcfe from $6.30 per Mcfe during the third quarter of 2009. Our overall average realized sales price continues to be boosted by our large percentage of oil production, which was 48% of total production during the fourth quarter, excluding adjustments from prior periods. Compared to the third quarter, production decreased 11% to 22.9 Bcfe in the fourth quarter. The production decrease primarily results from the sale of certain assets, which accounted for $25 million a day, starting October 28. Shut-ins due to Hurricane Ida in November, and production downtime at Main Pass-108 associated with the third party pipeline. Adjusted EBITDA increased 17% to $113.9 million from $97.5 million in the third quarter. The growth in adjusted EBITDA is largely attributable to growth in revenues resulting from higher average realized sales prices, as well as lower operating costs. Although our results can be lumpy at times, our quarter to quarter returning our EBITDA margins to the higher levels of the past is a key goal for us.

Let's discuss lease operating expenses, or LOE, for a bit. As we've mentioned before, internally we split LOE into five components -- base LOE, insurance premiums, workovers, facilities work and hurricane remediation. The hurricane remediation component is broken down into expenditures and then insurance reimbursements for such costs. Throughout 2009, we have been reducing base LOE, especially compared to 2008. For the sequential quarter comparison, base LOE was much lower and net hurricane remediation costs were down as well. This was almost entirely offset by increased workover activity. For the full year 2009, LOE decreased to $203.9 million, from $229.7 million at 2008. The year-over-year decline in LOE is due in large part to our divestitures, as well as the profitability initiative we successfully implemented throughout the year. We expect to see further declines in nominal LOE in 2010, as we will benefit from a full year of operations with these cost reductions.

Let me turn to liquidity now. We have good liquidity, despite paying down debt, paying cash dividends, and refraining from raising capital. Our cash balance at December 31, 2009, was $38.2 million, down $69.2 million from last quarter. We paid down the $142.5 million balance on our revolving credit facility. We've actually since redrawn that amount, and our cash balance is currently $250 million, and the undrawn capacity in our revolving credit facility is $262.3 million. If you will recall, we have an interest rate swap outstanding in the notional amount of $146 million, with a rate of 5.21% that expires in August of 2010. We redrew the revolver to generate interest income that helps offset the effects of the interest rate swap. We paid the revolver down at year end for credit enhancement purposes, rather than trying to describe debt to cap on a net-of-cash basis.

To reconcile the changes in the cash balance from the end of the third quarter to year end, cash flow from operations before changes in working capital was $144.4 million, and net cash flows from investing activities was $25.4 million, of which $23.9 million were proceeds from the sale of non-core assets in October. Conversely, we spent $142.5 million to pay off the balance of the revolver, reduced accounts payable, and had other working capital changes of $55.5 million. We spent $23.7 million on plug and abandonment activities, $14.9 million to repurchase common stock, and $2.3 million for dividends. In fact, for all of 2009, we have purchased 2,869,173 shares of our common stock at an average price of $8.43 per share for approximately $24.2 million, in the open market in accordance with the repurchase program we announced in March 2009. Repurchases were funded with cash on hand. We think this was a good investment. Also during 2009, we paid approximately $9.2 million in dividends.

Moving on to asset retirement obligations, or as we refer to as ARO, for all of 2009, we reduced our ARO by about $200 million through work performed, dispositions and revisions to previous estimates. We were able to do this despite a $77.3 million increase in ARO related to Hurricane Ike, majority of which relates to revised estimates for the dismantlement of two operated platforms that were toppled during the hurricane and the plugging and abandonment of the associated wells. Most of this increase in ARO is covered by insurance. In fact, almost $90 million of the $117 million current ARO obligation that appears on our balance sheet is hurricane-related, much of which is covered by insurance.

Let me discuss insurance receivables and claims for a moment. For the year 2009, we spent $37.1 million and received $18.7 million in insurance reimbursements associated with hurricane-related LOE, which resulted in a net expense of $18.4 million. This compares to $17.7 million last year. We anticipate the lease operating expenses will be offset in future periods to the extent that these costs are recovered under our insurance policy. As it relates to plug and abandonment activity covered by insurance during 2009, we spent $51.9 million and have thus far collected $25.1 million from our insurance underwriters for hurricane-related plugging and abandonment expenses. We have also recorded $30.5 million in accounts receivable for insurance claims yet to be reimbursed as of the end of the year. The significant portion of the insurance receivable relates to the P&A of wells and abandonment of facilities damaged by Hurricane Ike and is covered by insurance for the most part.

Finally, let me talk about taxes for a moment. In 2009, we received $17.7 million of tax reimbursements for 2008 federal estimated tax payments and $4.7 million for our tax loss carry-back. In the latter half of 2009, congress passed the Worker, Homeownership, and Business Assistance Act of 2009 that allows us to carry back losses to previously closed years. As a result, during the fourth quarter, we recorded an additional $38.4 million tax benefit to reflect the change in NOL carry-back. In 2010, we expect to receive around $85 million in tax refunds, with about $9 million in the first quarter of 2010, and the remainder in the fourth quarter of 2010. With that, I'll turn the call over to Steve Schroeder. Steve?

Thanks, Danny. Let me start with an update on our drilling program. During the fourth quarter, we successfully drilled two exploration wells. One well is in the Bay Marchand field and the other well is a 50% working interest discovery in the marshland of South Louisiana that found 30 feet of net gas pay. Following construction of facilities and pipelines, this South Louisiana well will be brought on production approximately mid year at an estimated rate of 5 million cubic feet equivalent per day gross.

Production for 2009 was about 95 million cubic feet equivalent per day. We drilled 10 exploration wells, eight were successful, and we drilled three development wells, two were successful. From that program, nine wells are currently producing at a combined net rate of about 2000 barrels of oil per day and 18 million cubic feet per day, or 30 million cubic feet equivalent per day. In addition, we did 28 recompletes that added approximately 39 million cubic feet equivalent per day of initial incremental production at a cost of $13 million. We also did 32 workovers for $6.3 million and added approximately 49 million cubic feet equivalent per day of initial incremental production. As you can tell, workovers and recompletes are a low cost, high return projects -- excuse me, low cost, high return projects that make a lot of sense. Given the essentially flat production, as compared to 2008, last year was a successful use of a limited capital budget.

For 2010, we currently plan on drilling 10 wells, or three more than our budget press release in January. As noted, we anticipate adding opportunities throughout the year. Three wells are exploring for oil and the other seven are targeting gas condensate reservoirs. One of the wells targeting oil reserves, in which we have 100% interest, was recently drilled, but not commercial, and was temporarily abandoned. We had success exploring in the main pass area, and we are currently drilling 100% working interest well in Main Pass-98 that targets similar seismic amplitudes to our recent success in the adjacent Main Pass-108 field. A discovery in our Main Pass-98 well would likely lied to additional delineation drilling later in 2010. This rig is then scheduled to return to the Main Pass-108 field with a well also targeting these same geologic zones. In March, a second jack-up rig is scheduled to drill in the Main Pass-283 field with the drilling of a [cris-i] exploratory oil well. Success here could also lead to additional offset drilling later in 2010.

Let's talk about production in 2010. We are producing about 215 million to 220 million cubic feet equivalent per day. While we do not expect immediate production buildup in 2010 from our drilling program in the first and second quarters, we do expect our recomplete and workover programs to add incremental production. So far in the first quarter, we have completed five recompletes and two workovers. Combined, we have added approximately 10 million cubic feet equivalent per day of production through recompletes and workovers. We also currently have four recompletes and four workovers that are in progress or pending. We expect this type of low cost and high cash flow work to continue throughout 2010 and into the future. One of the planned recompletes will be performed on the subsea well located in Green Canyon 646, our Daniel Boone completion. As reported last quarter, production from this well commenced in the late third quarter.

Due to early water production and decrease in reservoir production, or reservoir pressure, the initial zone has not performed as projected. We are planning to recomplete this well next month by utilizing smart completion technology. For the fourth -- for the first quarter of 2010, the Company anticipates production to be between 1.4 million and 1.6 million barrels of oil and between 8.9 billion and 9.9 billion cubic feet of natural gas for a total of between 17.8 billion and 19.7 billion cubic feet of gas equivalent. For 2010, we anticipate production to be between 4.6 million and 6.2 million barrels of oil and between 32.4 billion and 42.8 billion cubic feet of natural gas, for a total of between 60 billion and 80 billion cubic feet of gas equivalent. Please keep in mind that our guidance only relates to the initial seven-well program and does not reflect any buildup from the remainder of our capital budget.

Now I'm going to talk about lease operating expenses. Total lease operating expenses for the fourth quarter of 2009 were $45.8 million, which included a net reimbursement of the nearly $1 million for hurricane remediation. Even excluding the hurricane remediation costs, we were at the low end of guidance. The lower costs are a function of lower facility expenses, which were approximately $4.2 million under projections. As Danny mentioned earlier, we saw a decrease in LOE to $203.9 million in 2009 from $229.7 million in 2008. Base LOE and facilities expenses were the largest contributors to the year-over-year decrease. Base LOE declined $23.4 million, primarily due to the divestitures and the implementation of our profitability initiatives throughout 2009, and facilities expense fell $10.3 million, as we focused on completing hurricane-related repairs in 2009. These reductions in total LOE were partially offset by increases in insurance premiums, workovers and net hurricane-related LOE.

When we assess the results of our efforts to reduce costs internally, we focus on base LOE, the largest of the five LOE components that Danny described earlier, and one component which we have some control. On a percentage basis, we reduce the base LOE by 15% in 2009 compared to 2008. We expect base LOE to further decrease another 15% in 2010, as we benefit from a full year of cost savings related to the 2009 divestitures and profitability initiatives. In summary, LOE for the first quarter 2010 is expected to be between $45 million and $56 million and between $168 million and $206 million for the full year 2010. These estimates do not include any allowance for hurricane-related expenses or insurance reimbursements. Gathering transportation and production taxes for the first quarter 2010 are expected to be between $3 million and $4 million, and between $14 million and $18 million for the full year. Now, let me turn it to Tracy for closing remarks. Tracy?

Thanks, Steve. Before we take your questions on this call, I'd like to address some questions that have come up in our recent investor presentations. First, let's discuss the capital plan. When we first developed our initial budget, we had about 25 wells up for consideration in 2010. But I tell you, we have a deep inventory of prospects. I assure you, we can spend the entire $450 million on quality, internally generated prospects. However, as we continued through the process, we felt very strongly that the acquisition market is becoming more attractive and the JV opportunities were beginning to present themselves on a more frequent basis, so we felt we should allocate some of our budget toward those efforts.

Because so much of our acreage is held by production, those drilling prospects aren't going away. In fact, in some cases it can be to our advantage to allow technology, infrastructure or more data to develop and be available when we drill certain prospects. That being said, if we're not able to secure new transactions in a reasonable timeframe, we can always go to that original list and start drilling our own prospects. Ultimately the strategy is to grow reserves and production profitably. We are and have always been indifferent on how we accomplish this goal.

Another question is about what kind of changes we've made to our staff and organization. We've recently relocated exploration geology to Houston, allowing the exploration group to have a greater focus on new projects and to be closer to deal flow. Similarly, we're in the process of hiring staff to increase our M&A effort as well. Our additional staffing will add a layer of expertise in areas like onshore, where we'd like to be more active in the future. We're excited about our future opportunities, and we want to make sure we're ready to explore them.

Last, I would like to address questions that are being generated in the wake of the excitement around McMoRan's Davy Jones discovery. This is really good news for the Gulf of Mexico. This is another indicator there's remaining potential and upside on the Gulf of Mexico shelf. I've heard the death knell about the Gulf of Mexico so many times it's almost comical to listen to people say that the Gulf is dead. We plan to watch the progress of technology and situate ourselves to compete. Again, we believe that our large acreage position in the Gulf of Mexico has the potential to yield substantial results. We remain convinced that the Gulf is a world class basin, and that W&T has the people with the experience to exploit it.

Having said all that, I'll be glad to take your questions. Operator, if you would, please open the phone lines for Q&A.

(Operator Instructions) Our first question comes from the line of Neal Dingmann with Wunderlich Securities. Go ahead, sir.

Good morning, guys.

Good morning, Neal.

Say, Tracy, maybe if I can get a little more color on this. On your production guidance, I think you mentioned, or just recently was mentioned about -- that just includes now the seven-well program. Maybe explain a little bit as far as the recompletes, the workovers, and then some of these other additional wells, so there obviously is some upside to that. Maybe give us color of what that does entail.

Yes, you're right. The -- that guidance just considers that seven-well exploration program. It does include some buildup from, from that program, as well as some buildup from workovers and recompletes.

Okay, okay. And then looking a little bit, you mentioned the acquisition side. Just wondering, you know, when you look out there, two things around that. One, on your side, anything else non-core that you'd be considering selling? And then on the purchase side, you know, I assume you will always look, you know, wherever the best cash flow onshore, offshore. Do you still see the most favorable offshore in your opinion?

I'm going to take the first part of that question and say yes, we are considering more non-core dispositions, and we're going through those numbers as we speak. And second, acquisitions onshore and offshore are going to be an integral part of what we're doing. We're starting to see that bid ask number close. It doesn't really matter, Neal, whether it's onshore or offshore. It's just a profitability question for us. And really quite frankly, it doesn't matter whether it's oil and gas. It's still a profitability issue for us.

Okay. If I could sneak one last one in.

Sure.

Just on the borrowing base, maybe for Danny, where that currently sits and, you know, will that be reevaluated, or is that safe now?

The borrowing base gets redetermined every six months. It's currently at $405.5 million, and that's where it'll be until the next redetermination.

Which is?

Should be April.

Got you. Thanks, guys.

Thank you, sir.

And our next question comes from the line of Chris Gault with Barclays. Go ahead, please.

Hey guys, good morning.

Good morning, Chris.

For the CapEx part of the budget that is for acquisitions, how do you expect that you'd finance that? Is that just going to be probably through credit facility borrowings, or do you think you'd issue equity? Can you give us your thoughts on that?

I think that would be a function of what the size of the acquisition would be. We're certainly not opposed to issuing equity for something that's, that merits it. We've done that in the past. In fact, we did that with the Kerr-McGee acquisition. But other than, I mean that line is $405 million, and we still got a lot of availability under that line. Obviously I would always prefer to borrow under the line because that's our cheapest source of capital.

And do you think you could do just that 300 that's currently in the budget, just under the credit facility then?

The short-term answer to that is yes.

Okay. Thank you.

(Operator Instructions) And our next question comes from the line of Richard Tullis with Capital One Southcoast. Go ahead, please.

Thank you, good morning.

Good morning, Richard.

Moving back to Daniel Boone, I know some comments were made in the prepared remarks about having to go in and recomplete the well. Could you give a little more detail on what's going on there?

Sure. We've had a little premature water break-through. The current production is about 1,800 barrels oil per day gross, about 1,800 Mcf a day gross. Looks like the GOR has drifted down a little bit. Along with that, we've increased the water production to around 1,000 barrels or so a day. So the water cut is coming up. Looks like permeability is just a bit lower than we had thought. We're going to change to this other zone. We will still be able to go back to that zone. Hopefully it'll repressurize and we'll get a little more production out of that as well.

What's your cost estimate on that additional work?

It's, it's really -- it's not very much. I don't have an exact estimate. We can do it from the platform.

Okay.

So there's no rig involved.

How much Daniel Boone production do you have roughly say in your 2010 guidance?

Well, I'm not really sure about that right offhand, Richard. I can't answer that question.

Okay. What sort of impact did it have on 2009 reserves, if any?

I think there was some impact. I can't tell you exactly what it was, but certainly, certainly didn't help our reserve situation any.

Okay. For the 10 wells that -- exploration wells identified in the 2010 CapEx program -- what's the predrill reserve estimates on those?

We don't normally give out predrill reserve estimates. Our intent here is to come up with something that will hopefully replace all of our reserves organically.

Okay, and how many rigs currently running?

We've got three running right now. We've got two operating and one non-operating.

Okay, and if you could, talk about shelf rig rates now, say, compared to 2008 and even going back earlier.

Well, the same type of rig that we were paying $120,000 a day for this time 2008, we're paying about $40,000 for now.

Okay. You know, given all of that, and the 160 prospects and identified in the portfolio, I mean how, how soon do you think, if you don't find a suitable acquisition, would you go back to aggressively adding wells to the exploration program this year?

Well, actually we're doing that now. This is an ongoing process. So I expect that by the end of the year, we're going to replace reserves. That's our intent. Whether we do it with a drillbit or whether we do it with acquisitions and the drillbit, will be ideal.

And that excludes--

Our intent is, we're not sitting around waiting, hoping that something will come across our laps and we'll buy it. We're aggressively pursuing prospects that we think are top quality.

Okay, and then the replacement of reserves, that's outside of any sort of price-related revisions?

Yes, sir.

Okay. All right, thanks so much, Tracy.

Thank you.

And our next question comes from the line of Noel Parks with Ladenburg Thalmann. Go ahead, please.

Good morning.

Good morning, Noel.

Just a couple things. I -- and I apologize if you addressed this. I think I heard something about it, but I was distracted for a bit. The asset requirement, asset retirement line once again declined very nicely sequentially this year, and was that more divestments, or was that more just your devoting energy to some of those tasks this quarter?

Noel, if I could, the ARO went down almost $200 million. Well over half of that came from the divestitures. Some of it came from revisions to estimates, but the majority came from the divestiture.

Okay, great. And just looking ahead here in my notes, and if -- by my calculations, you were free cash flow positive last year. Assuming that there isn't anything happen -- assuming no acquisitions, do you think you'll -- I guess with the current budget, looks like you probably won't be in that situation this year, am I right? You'll need to draw a bit on the credit line?

We should be able to fund the capital program with cash on hand, internally generated cash.

Oh, okay. Okay, great. And I guess just one last thing, talking about acquisitions, would you and the other parties in the gulf, and you did talk about the recent ultra deep successes that have been out there and how that certainly gives you a few new ideas. Is there much going on in terms of people actively looking into perhaps swapping properties or trading interests to consolidate interests to have a little bit more control over how folks might develop some of the areas -- or might be increasingly derisked by some of the recent developments?

That's pretty comprehensive question. Let me tackle it in parts. First, as a matter of course of business in the Gulf of Mexico over my career, I've noticed that operators tend to try to garner more of that interest in their prospects that they have interest in already. You don't necessarily want to be operator, because it's fun to do operations. You want to be an operator so that you can control your destiny.

Sure.

So that part of it's an ongoing thing. And we do that, and other companies do that as well. As far as securing additional acreage around -- I think that's what you're asking -- around some of the recent discoveries, is that what you asked me?

Yes.

I mean we've got a lot of acreage in the gulf, so we've got that position already. We have some fairly large structures on things that we have in our own inventory. I think that, you know, when you start talking about drilling to 30,000 feet for a gas prospect, you kind of need to take a look at your whole card there and figure out what you think your economics are going to be. That's the limiting factor. The price of gas hasn't been going up lately.

Sure, sure. And I guess just one last thing, was there -- again, I apologize if you mentioned this before. Mahogany Deep, did you comment any on what you've been doing there with seismic and reprocessing on some of the data there?

We do have some new data there, and we are looking at that. That project is still on our books. I haven't authorized -- we haven't authorized to drill it this year. However, I will tell you that we have some more data.

Okay. Any sense of, you know, in the next quarter or so if you'll be closer to making the decision or, you know, taking advantage of service costs and maybe bringing that into some point in the quarter, you know, if we assume gas doesn't deteriorate too much from here?

I'll pull that question over to Jeff Durrant regarding looking at the data. I'm not sure what your schedule is Jeff. Maybe you can give him some color on that.

Yeah, I sure can, Noel. We recently have just loaded up a new data set covering the Mahogany area and even the surrounding areas. It definitely takes a little time to work on this regionally. When you're talking about drilling 25 or more thousand feet, you're not going to drill it one-off, and so we're looking at the whole area as a whole. So I, I would expect that it will be taking a good part of the rest of this year to get our regional work together and, and get to the details on the deep prospect at Mahogany.

Okay, and your assumption is that you would -- do you think you would be keeping the operatorship and the majority of the interest in that when it came time to drill, or would you be looking to partner up on that since, you know, only in the last couple of years, you get -- consolidate the working interest there?

I would expect that we would have the operatorship there, Noel. We have the facility and it's in 500 feet of water, and we've got all the production capabilities at Ship Shoal 349. So that's really -- that's really where we're going. We do expect we'll have some partners there, though.

Okay, great. That's all for me. Thanks.

Thank you.

Thanks, Noel.

(Operator Instructions) And our next question comes from the line of Dan McSpirit with BMO Capital Markets. Go ahead, sir.

Folks, good morning, and thank you for taking my question.

Good morning, Dan.

Good morning. With regard to your acquisition strategy, particularly moving onshore and further diversifying your asset base as it stands today, can you speak to your in-house expertise or even experience in scaling and onshore operation?

Sure. We've got a lot of in-house expertise onshore. Not only with me, but with our geological staff and our operations staff. We've operated as W&T or other entities in probably nine, 10, 11 states in the U.S, in different basins, North Dakota, Utah, Texas, West Texas, Appalachia -- bunch of different places that don't necessarily show up on the resume, but I don't think that going out and drilling wells in West Texas or Appalachia or the Rockies is that much of a challenge when you compare it to drilling a well in 4,000 feet of water in the Gulf of Mexico.

Understand. Thank you.

Thank you, sir.

And there are no further questions at this time. I'll turn it back to management for any closing remarks.

Well, I think that does it for the day, operator, and we appreciate it and we'll talk to you guys next time. Thank you very much.

And, ladies and gentlemen, that does conclude your call for today. Thank you for joining us, and have a good day.