SilverBow Resources Inc (SBOW) 2009 Q2 法說會逐字稿

Good afternoon. My name is Mark, and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy second quarter 2009 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions).

Thank you. Mr. Paul Vincent, you may begin your conference.

Good afternoon. I'm Paul Vincent, Manager of Investor Relations. I'd like to welcome everyone to Swift Energy's second quarter 2009 earnings conference call.

On today's call, Terry Swift, Chairman and CEO, will provide an overview. Alton Heckaman, EVP and CFO, will review the financial results for the second quarter. And then Bruce Vincent, President, and Bob Banks, EVP and COO, will provide an operational update. Terry Swift will then summarize before we open it up to questions. Also present on the call today are Mike Kitterman, SVP, Operations, and Jim Mitchell, SVP, Commercial Transactions and Land.

Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates, and projections about us, our industry and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports, to which we refer you, along with cautionary statements contained in our press releases and our actual results could differ materially.

Today, Swift Energy also announced a secondary common stock offering. We will not be discussing or taking any questions directly or indirectly related to this offering during today's conference call. We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Thanks, Paul. Thank you again for joining today's conference call.

As planned, we did not undertake any new drilling operations until the latter half of the second quarter of 2009. By allowing time for industry service costs to come in line with hydrocarbon prices, focusing on recompletions and improved operating efficiencies, Swift Energy performed at or above its operational and financial guidance targets for the quarter.

This level of performance stems from the exceptional efforts and focus of everyone in the organization. Although there was minimal drilling activity during the first six months of the year, Swift Energy has properly positioned itself for future growth and has streamlined its operation while hydrating its drilling and new inventory across all its core areas.

During the second quarter, oilfield drilling and service costs continued to moderate while crude oil prices stabilized and then began to improve during the quarter. Unfortunately, natural gas prices declined due to demand pullbacks related to the global recession.

The outlook for the E&P sector for the rest of 2009 and heading into 2010 remains uncertain, but we are beginning to see signs of stability that cannot be ignored. The significant decrease of the oil and gas industry rig count is a leading indicator of future supply reductions, particularly natural gas supplies.

With the recovery of oil prices to the $50 to $60 range, we are beginning to realize higher than budgeted cash flows, which will enable Swift Energy to enter 2010 with an emphasis on reserves and production growth. Therefore, we are increasing our 2009 capital expenditure budget from $125 million to $150 million range to $160 million to $180 million range.

Additional spending in 2009 will be directed towards growing oil production in Lake Washington through a recompletion and shallow and intermediate drilling program targeted at proved, developed, probable and possible reserves. We'll also spend the money expanding our horizontal drilling operations in the Olmos formation and AWP, commencing horizontal drilling operations in the Eagleford Shale formation and drilling oil wells in the northern portion of AWP as well.

We expect this increase in activity will deliver a daily production rate of 24,000 to 26,000 net barrels of oil equivalent to the Corporation by year-end.

We also have taken steps to improve the financial aspects of our business as well. We reduced borrowings on our credit facility during the second quarter, when compared to the first quarter, and continue to work with vendors and service providers to reduce costs in our day-to-day operations. We believe that with an increased liquidity profile and increasing operational momentum, that the Company is well-positioned to grow its asset base while generating appropriate returns for our shareholders.

Additionally, and as another sign that the direst period of the current economic downturn may be behind us, the capital markets have recently become active. Recognizing the current availability of the capital markets, Swift Energy also announced a public offering of common stock this afternoon, after the market closed, in a separate press release. Additional information relating to this offering will be disclosed after the offering has closed.

Operationally, even with a significantly reduced capital spending budget and activity levels, Swift had an excellent quarter. Bob and Bruce will review all of our operating activities in the next few minutes, but first, I'd like to take a few moments to touch on the highlights and applaud the efforts of everyone in the organization who were asked to do more with less, and met or exceeded our expectations.

Operational highlights of the quarter include the completion and connection of sales for the BDC UC #8 well in our Bay de Chene field, which is not only performing very well, but it represents another step forward in the recovery efforts from Hurricane Gustav last fall. This well was actually drilled during 2008, but could only recently begin flowing to sales, as repairs in the field progress.

This well began flowing to sales in mid-May, and for the month of July, produced at an average rate of 5.3 million gross cubic feet per day of gas. Currently, we expect all repairs at Bay de Chene to be concluded by the end of the third quarter 2009.

The Shasta discovery, also in South Louisiana, was brought online and flowed steadily throughout the quarter. The performance of this well will be very helpful, as we prepare our exploration and exploitation inventory in the very high-potential fairway developing between Lake Washington and Bay de Chene.

Our first horizontal well in the Olmos formation, drilled late last year, continues to perform well and has affirmed our belief that the AWP field limits can be successfully extended, using new drilling and completion technologies. The first well of our 2009 horizontal drilling and completion program, targeting the Olmos formation at the AWP field, recently finished drilling and is being prepared for completion. The rig that drilled this well will soon be moved to begin drilling operations on the second well of this 2009 program.

With the planned increase in capital spending for 2009, this Olmos horizontal drilling program has expanded, and will continue into 2010; and a number of oil locations will also be drilled in the northern part of AWP as well. Swift Energy is also planning to drill horizontally in the Eagleford Shale formation during the second half of the year in the AWP field area.

Further, Swift Energy is also considering a strategic joint venture with an industry partner to accelerate the Eagleford Shale development and increase the value of its existing acreage position. Although we are still in the early stages of the evaluation, many industry experts believe that the Eagleford Shale would have resource potential similar to the Haynesville Shale play.

In our central Louisiana/East Texas core area, the Company recently entered into a joint venture with Anadarko for development and exploitation in and around the Burr Ferry field in Vernon Parish, Louisiana. The Company, as fee mineral owner, leaves a 50% working interest in approximately 33,600 gross acres to Anadarko. Swift Energy will retain a 50% working interest in the joint venture acreage, as well as a fee mineral owner's rights that we have there.

Anadarko is an outstanding operating partner who's built an exceptional track record in the Austin Chalk development and value creation.

Although the oil and gas environment, and the US global and economic conditions remained difficult during the second quarter, the outlook for the rest of the year has improved substantially. Higher oil prices, operational improvements, and increased cash flows have encouraged us to increase our 2009 capital spending. The expanded operations will target value-added projects, which will enable us to grow our production and reserves substantially in the future.

And with that, I'll ask Alton to present the second quarter 2009 financial results.

Thank you, Terry, and good afternoon, everyone. The oil and gas sector continued to experience a low, although somewhat improving, commodity price environment during the second quarter of 2009. Swift Energy's financial results for the second quarter reflect this.

Revenues were $82.9 million, a 68% decrease from 2Q '08. Our loss from continuing operations was $2.2 million, or $0.07 per diluted share, down significantly from 2Q '08 levels, yet beating first-call mean loss estimate of $0.13. Cash flow before working capital changes decreased 77% per diluted share to $1.36, and 2Q '09 production decreased 16% to 2.3 million barrels of oil equivalent.

Both crude oil and natural gas prices are substantially lower than second quarter 2008 levels. Swift's average realized price in 2Q '09 decreased 62% to 36.71 per BOE, due primarily to crude oil prices declining to an average of approximately $55 per barrel when compared to approximately $125 per barrel in 2Q '08.

Natural gas prices declined also to an average of just over $3 per mcf, compared to over $10 per mcf one year ago, resulting in a decrease in our quarterly oil and gas revenues of 69% when compared to the second quarter 2008. With the pricing decline, we have continued to focus on our controllable per-unit cost and metrics, especially given the decline in volatility and the downturn in the oil and gas industry.

G&A came in at $3.36 per barrel on the low side of our guidance. Our DD&A per unit came in at $17.90 per BOE, below our guidance. Production costs came in well below guidance at $8.34 per barrel, as costs in several categories were reduced. Interest expense came in at $3.46 per barrel, below our guidance, due mainly to lower interest rates on our line of credit. And production taxes came in within our guidance as a percentage of revenue. The result, as I mentioned, was a loss from continuing operations for the quarter of $2.2 million or $0.07 per share, both basic and diluted.

Cash flow before working capital changes for 2Q '09 came in at $42 million or $1.36 per diluted share, while EBITDA was $47 million for the quarter. The quarterly CapEx on a cash flow basis of $32 million -- you can see how we lived within our cash flows.

Given the recent global credit crisis and the effect on the financial markets, let me spend a moment to highlight Swift's solid financial position and discuss a few of our cost containment initiatives.

As I mentioned, Swift continues to maintain our conscious historical decision to maintain our CapEx within our cash flows. Our two senior notes that are currently outstanding have very good interest rates and are well aligned with our long-term assets.

As previously mentioned, we fully expect the rest of 2009 will continue to be a difficult but improving operating environment, and will require continued discipline and emphasis on controlling our costs across the enterprise. In 1Q '09, we implemented a reduction in our workforce and have also implemented other cost-saving initiatives in the G&A area that will have an impact going forward, and it's reflected in our guidance.

And as Terry mentioned, we continue looking closely at our capital expenditures and operating expenses, and have identified several cost-saving opportunities in all of our core operating areas. We also are working closely with all of our vendors for additional cost savings for the goods and contract services.

With respect to our line of credit with our 10-member bank group that currently runs through October 2011, our borrowing base and commitment amount will remain at $300 million.

Swift had an outstanding balance underline of $228 million at the end of the second quarter and that has come down since then. Our current cash forecasts, however, do not anticipate our drawdowns exceeding $250 million at any point during 2009, so we therefore feel our liquidity and resources are solid and available to weather these financial times.

We will continue to maintain a conservative financial discipline and have a 2009 budget that enables us to live within our means with limited drawdowns on our line. We are in compliance with our debt covenants and expect to remain fully compliant in all future periods.

And as always, we've included additional financial and operational information in our press release, including initial guidance for the third quarter of 2009 and the full year.

These remain difficult times in our world and in our sector; Swift is well-positioned financially to take advantage of the opportunities and always present themselves during periods of uncertainty and adversity. We've been through these cycles before and we're up to the challenge.

With that, I'll turn it over to Bruce Vincent for an overview of our operations.

Thanks, Alton, and good afternoon, everyone. We appreciate everyone listening in.

Today, I will discuss our second quarter 2009 activity, including our production volumes; our recent drilling results; activity in our core operating areas; and more importantly, our plans for the rest of 2009. Bob Banks will then provide greater detail on a couple of our activities we want to highlight today.

Beginning with production -- Swift Energy's production during the second quarter of 2009 totaled 2.26 million barrels of oil equivalent; 13.53 billion cubic feet equivalent. This was slightly above the high end of our second quarter 2009 production guidance, primarily as a result of better-than-anticipated performance from our Bay de Chene field.

Second quarter production decreased 16% from the 2.69 million barrels of oil equivalent, or 16.16 billion cubic feet of oil, produced in the same quarter of 2008 as a result of no new drilling activity, the shut-in production at Bay de Chene, and natural declines. Sequential production decreased 5% when comparing second quarter 2009 to production in the first quarter of 2009.

Now for our drilling results. Swift Energy completed one development well in Bay de Chene during the quarter. The well, the BDC UC #8, was drilled in 2008, but could not be completed until repairs in the field had been made to damage caused by Hurricane Gustav.

I'll briefly review our activity in each of the four operating areas, starting with the Southeast Louisiana core area, which includes the Lake Washington and Bay de Chene fields.

Production during the second quarter of 2009 averaged approximately 13,025 net barrels of oil equivalent per day or 78 million cubic feet equivalent per day in this area, which is unchanged when compared to our first quarter 2009 average net production from the same area.

Lake Washington averaged approximately 9,976 net barrels of oil equivalent per day or 60 million cubic feet equivalent per day, a 6% decrease when compared to first quarter 2009 volumes. This production decline was offset by Bay de Chene's sequential production increase of 25% to 3,049 net barrels of oil equivalent per day or 18 million cubic feet equivalent per day.

This increased production is primarily due to the completion of the BDC UC #8. Oil volumes in Bay de Chene, along with low pressure natural gas, remain shut in until further hurricane-related damages are completed later in the third quarter. In total, we estimate approximately 1,500 to 2,000 net barrels of oil equivalent per day of production are currently shut-in in this field.

At the Lake Washington Field in Plaquemines Parish, Louisiana, an extensive production optimization program involving gas lift enhancements and sliding sleeve shifts, which began during the first quarter of 2009, continued during the second quarter. Bob will provide more details on this program, as well as update the Shasta well, which is now flowing [to sale].

In Bay de Chene, the Company expects to have rebuilt the infrastructure, that was damaged or destroyed during the 2008 hurricane season, online by the end of the third quarter. All shut-in production should be restored upon completion of facilities construction. These upgraded and new facilities will be more durable and should prevent extensive downtime after severe weather events in the future.

Swift Energy maintains a growing drilling inventory at Bay de Chene, which will also be viable once these facilities are in place. The Company continues to evaluate low-cost methods to increase its oil production during 2009 in its Southeast Louisiana core area.

Bob will discuss how today's announced increases in our capital expenditure budget will impact activity in this area this year.

In our South Texas core area, which includes our AWP, Sun TSH, Briscoe Ranch, and Fasken fields, second quarter 2009 production averaged 7,351 net barrels of oil equivalent per day or 44 million cubic feet equivalent per day; a 12% decrease in production when compared to first quarter 2009 production in the same area. This decrease is primarily a result of significantly reduced drilling activity in the areas.

The first well of our 2009 horizontal drilling and completion program, targeting the Olmos formation of the AWP field, recently finished drilling and is being prepared for completion. The rig that drilled this well will soon be moved to begin drilling operations on the second well of the program. Bob is also going to discuss this program in more detail in a few minutes.

Essential Louisiana/East Texas core area, which includes our Brookeland, Masters Creek, and South Bearhead Creek fields, contributed 2,441 barrels of oil equivalent per day of production in the second quarter of 2009. Terry mentioned earlier the recent farm-out of a 50% working interest in the 33,623 acres in this area, to Anadarko, which we believe will bring increased activity, beginning next year.

In our South Louisiana core area, which is comprised of Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island, and Bayou Penchant, reduction averaged approximately 1,774 barrels of oil equivalent per day, or 10.6 million cubic feet equivalent per day, during the second quarter -- a decrease of 21% when compared to first quarter production in this area, primarily a result of reduced activity levels and natural declines.

And now I'm going to turn the call over to Bob Banks to review some of our more notable activity during the quarter.

Thanks, Bruce. First, the Bay de Chene UC #8, which was drilled in 2008 but could not be completed until repairs in the field had been made for the damage caused by Hurricane Gustav, was completed in the second quarter. This well was drilled to a depth of 14,176 feet and encountered 66 feet of true vertical pay in two zones.

This well began flowing to sales in mid-May, and for the month of July, produced at an average daily rate of 5.3 million gross cubic feet per day of gas, with a current flowing tubing pressure of 1,220 psi. The inventory at Bay de Chene has grown, and we view this field as having very high potential for our future.

We brought the Shasta discovery well online April 26 and it is now producing to the Westside facility in Lake Washington. For the month of July, this well produced an average daily rate of 4.6 million gross feet of gas per day and 329 gross barrels of oil per day at 9,600 psi on a 14/64th-inch choke.

Swift Energy has a 50% working interest in this well. We continue to monitor the reservoir's performance, as it is an important well in our understanding of the play fairway, which is developing between Lake Washington and Bay de Chene.

As Bruce mentioned, we continued a production optimization program in Lake Washington during the quarter. Well work was completed on 13 wells and three recompletions were performed during the second quarter. This low-cost program will continue throughout the year and will assist in the mitigation of natural field declines until we begin drilling operations in the field.

In Lake Washington, we have developed 10 recompletion opportunities and five to 10 new drilling opportunities, which are actionable this year. As a result of increased capital availability, we will begin these programs this year and they will continue into 2010.

Moving to the AWP field, located in the Company's South Texas core area, the R Bracken 34H well, the first well of our 2009 horizontal drilling program in the Olmos formation this year, was recently drilled. In this well, we drilled a 3,700 foot lateral end formation with good gas shows throughout. We have run our 4.5 inch production liner [to TD] and will fracture stimulate the well later this month. We expect to be able to bring it online by the end of August.

We are also moving the rig that drilled this well to a new location to begin drilling the second well of this program. As this program builds momentum, we will begin evaluating its potential impact on expanded resource potential and reserves bookings.

Also, in our AWP field, we are focusing our attention on evaluating the Eagleford Shale formation. 60,000 of the approximate 89,000 acres prospected for this formation in our South Texas core area are located in and around the AWP field, most of which we believe to be on trend with current competitor activity in the area. We are currently forming a strategy to accelerate the development of our prospective Eagleford Shale acreage, which will consider all options available to us, including the addition of a potential joint venture partner.

Swift Energy does plan to drill a horizontal well to test the potential of the Eagleford Shale formation during the second half of this year. The increased capital spending and activity level will deliver a daily production rate of 24,000 to 26,000 net barrels of oil equivalent by year-end 2009.

Thanks for your attention this afternoon and I'll turn it back to Terry to recap.

Thanks, Bob. Before we open the line for questions, I want to summarize Swift Energy's second quarter results.

To review some of the highlights from today, we have a low-cost production enhancement program, which continue to produce excellent results and help mitigate natural declines in Lake Washington during the quarter. We intend to continue this program and expect to add up to another 10 re-completions to the 2009 program. We will also begin drilling shallow and intermediate depth oil wells in this field during the second half of the year.

At Bay de Chene, repairs continue to move forward on schedule, and all shut-in production as a result of Hurricane Gustav should be restored by the end of the third quarter. We also continue to grow our high-value inventory of development and exploration projects here.

Our first horizontal well in the Olmos tide gas sand drilled last year continues to perform at the high end of our expectations. And the first horizontal well of our 2009 Olmos development program has recently been drilled. The next well of the 2009 program will soon spud, as the rig is moved on to location and the program will then continue into 2010. These wells have successfully extended the original field limits of the AWP/Olmos field.

Oil price increases and operational efficiency gains have improved our cash flow and our outlook for 2009. We have taken various steps to improve our liquidity, and intend to further reduce our bank borrowings throughout the year. Swift Energy's 2009 capital expenditure budget was increased to $160 million to $180 million from the previous $125 million to $150 million budget range.

Additional spending will be directed towards our South Louisiana and South Texas areas, and we believe that we'll deliver a net corporate daily exit rate of 24,000 to 26,000 net barrels of oil equivalent per day by year-end.

At this time, we'd like to begin the question-and-answer portion of our presentation. But before we start, I would like to remind everyone that we will not be taking any questions related to our stock offering during this conference call.

(Operator Instructions). Leo Mariani.

A question on your JV with Anadarko there. Any specific formations that they're targeting over there? And just curious as to kind of more specifically what the financial terms are that's heads up or you guys are getting carried in any of the wells over there?

As you are aware, Swift Energy has drilled in the Austin Chalk for many years. We have a position over in Brookeland as well as Masters Creek. And the Burr Ferry position lies really on trend between those two fields. Some of that Burr Ferry acreage actually goes a little bit farther down a bit, where they're seeing some success over in the Brookeland area, extending the field down dip.

We've watched other players, including Anadarko; they've been active over in the Brookeland area drilling wells. We think there's a good opportunity to take some of this acreage, where we are the royalty owner -- we own the [Creek] -- and work with another player. In this case, it's Anadarko, where they will specifically be going after the Austin Chalk in that area. That's pretty much the plan. A good operator, a good partner to have. We think it's a good move.

Okay. Is that basically going to be heads-up, 50/50 on wells going forward?

Well, the actual terms of the farm-out remain confidential. Anadarko will have a 50% interest in the venture going forward. They're going to need some time to figure out how many wells they exactly want to drill. We'll be working with them on that. It's very much a joint venture relationship, structured to be 50/50.

Okay. I guess, jumping over to your AWP field. You guys talked about doing some shallow oil drilling in the northern part of the field. I guess, my understanding was that was principally a [bad] gas field to you guys. Could you talk a bit more about some of the shallow oil zones over there and whether or not you've tried to exploit that in the past? And if you have a sense of what the economics may be on some of that drilling.

Yes, I'll take that. AWP has principally been a gas field; but if you go back to its original development, particularly to the north, in acreage that we weren't a subsidy player in, there was a fair amount of gas. Those wells, excuse me -- a fair amount of oil, and they're shallower.

Typically, you could look at a well in that area coming in at 50,000 barrels a day on the low side to 300,000 -- excuse me, reserves -- 50,000 barrels of reserves on the low side and 300,000 barrels of reserves on the high side. We found some areas that are in that shallower area. And we're looking at wells that are probably in the mid to lower range of that, but in this oil market, they're great wells, coming in the 100 to 200 barrel-a-day range with a simple frac job, typically 40 acre spacing. Individually, not big things but as a package, we think they're real nice investments.

What kind of costs are associated with those wells up there?

Under $1 million for those wells.

Okay. Sticking with this sort of well cost question, I'm curious as to what that Olmos well cost you just really -- you just finished drilling, do you have a sense of well cost on that?

The horizontal wells?

Yes. The first horizontal well cost us about $9 million, but we did a lot of finance on that well, a lot of over-engineering. We shot some of the micro-seismic and offset monitor wells.

This next batch of wells we think are going to come in the $7 million to $8 million range; but we really expect to get these well costs down into the $6 million to $7 million range, depending on whether or not we're able to move the intermediate casing string, which we're looking at very seriously for, maybe not this next well, but wells down the road.

Okay, thanks, guys. Appreciate it.

Joe Allman.

On the increased CapEx budget, with that increased budget, do you still expect to underspend cash flow for the third quarter and fourth quarter?

And what are you assuming in terms of commodity prices in that estimates for the third quarter and fourth quarter?

Our expectation -- we're kind of actually just borrowing the equity offering. We really divided it up in kind of a Phase I to Phase II approach; moving ahead with Phase I, given a certain outlook for prices, expanding them into the Phase II or the larger end of that spending range.

The plan is to really spend cash flow. Obviously, balancing that precisely by the end of the year is probably not easy to do, but we think we'll end up spending pretty close to cash flow. We've historically done that. We've operated with what we've often called a discretionary spending ledge in our capital budget; we like to spend realized cash flow, not forecasting cash flow.

And so as we move through the year, we have a better idea of where we're going. Right now, what we tend to do is we look at the strip that we balance that with a governor on it by looking -- by not using prices more than the past 40-day moving average. It keeps us from getting too aggressive in trying to possibly outspend cash flow.

Okay, that's very helpful. And then with your expectation for production to rise between now and year-end, what do you think the biggest drivers are for that increase in production?

Well, obviously, the biggest driver from our perspective is just the implementation of the program. We've got everything lined out and we're ready to put the rigs back to work. We had purpose to slow things down and, in fact, wait for these rig costs to get down and steel costs to get down. They're very much in line with where we want them. We've got our permits; we're ready to go in virtually all of the areas.

And we've got some ways of shifting things around to -- well, I would say timing is probably the most interesting piece to put in there. We've got all that lined out.

So, whereas before, I think you were looking for a decline in production. Is it pretty evenly spread out, the contribution from the different programs? Or are there a couple of programs that are going to contribute more to the increase between now and year-end?

That's a good question, and probably the best way to answer is, is that we've risked all of these results -- that's the way we do it -- we risk them on the timing; we risk some of the initial expectations. And based on the risk, I think it's fairly well spread between South Louisiana and South Texas, with maybe just a little bit more in South Texas; but if you take the oil piece that we put in South Texas, it's probably better said it's spread between oil and gas.

Okay. And I guess you've got some hurricane risk in there too, is that right?

Yes, I'm not sure how you forecast that. We obviously talk about that all the time and try to put a little in there, but -- if we were completely allow for that, then -- we don't know what that's (multiple speakers).

Yes. And when I say timing, that's a good point. The hurricane probably -- the hurricane factor is probably the most difficult one to figure out, but we do have something in there for it.

Got you. Okay, very helpful. Thank you.

(Operator Instructions). Andrew Coleman, UBS.

I had a couple of questions here. Looking at the way spending is going to ramp up there in the third quarter, that looks like it's more an optimization activity. Is it fair to assume then that most of that will be expensed? Or will you be able to capitalize some of that?

A lot of that's going to be capitalized.

Well, the -- yes, the -- yes, some of it will be expensed and some of it's capitalized. It just depends on what the specific activity. But the recompletion work as specifically planned for third and fourth quarter, much of that will be capitalized.

Okay. And then thinking about how I guess LOE is going up a little bit on a per-unit basis. Has that been more driven by just a commodity price outlook or what?

It's really driven by the lower production rates in the third quarter than anything else.

That, and we had some non-operated plants (multiple speakers) that came back online the latter part of the second quarter, that will be running at 100% third and fourth quarter.

Yes, in particular, that's the [Waclosky] plant, that which you're probably familiar with in Plaquemines Parish. That has been offline in the first and second quarter as a result of the hurricane last springtime. And Swift has actually an equity interest in that when that comes back online. The values is you get to sell your -- you get revenue from the liquids that go through that; the negative is it increases your LOE.

Okay. All right. Then thinking about there's higher -- slightly higher oil price environment, with the additional spending that's going to happen this year, do you foresee being able to, I guess, replace all of your production across your regions this year?

Well, I don't think we expect to replace all of our production across each region, because we're not allocating the capital that way. Much of the capital is actually being allocated to Southeast Louisiana and South Texas, as opposed to the other two.

Okay.

I think we'd added that -- earlier in the year, we did guide towards a small reduction in reserves. And given that we don't have the level of activity to really be chesting out all these new opportunities, we're going to kind of stay with that guidance. But I would mention that in South Texas, in particular, there is a significant resource play or resource potential reserve that we're going to be evaluating and appraising through the drill book.

Yes, there's a little bit of a wild card, obviously, this year for us and everyone because of the new SEC reserve disclosure rules. And also because, in our particular case, because of the expanded resource play, both in the Olmos and the Eagleford, depending on the activity we get and depending what we feel and our outside engineers feel that we can actually book, that will certainly have an impact on that reserve replacement number.

Okay, great. And the last question I have is -- does the guidance that's in this release, does it incorporate your operating? Or should we assume that we get some additional color down the road here?

We can't really comment on the offering. I think everything that we've discussed here today is relevant to the -- or that we intend to discuss is relevant to the second quarter and our outlook for how we believe we can go forward, given the present environment.

I think what we can say, Andrew, is the earnings release was made prior to the release of launching the offering.

Okay, great. Thank you.

Kevin Smith, Raymond James.

Just had a few questions. First, what type of rate of return are you expecting in your Olmos drilling program? And really more, I guess, where do you think gas prices need to be for those wells to be economic?

Yes, I mean, actually, we think at $4 gas, they're very economic for us, especially if we can drive these drilling costs down. So, we can make money at $4.

Yes, I think -- we think the Olmos specifically is a 3 to 5 Bcf type well; use 4 as a mid-range; you get the cost under $7, you're going to find sub-$2.00 drilling finding costs in there. So we think $4, $4.50 market, that's very economic in that environment. We've got infrastructure in place, the additional operating costs through another Olmos well and a field with 500-plus wells is negligible.

What type of -- I know it's gas well, but I mean, is it, like, 100% methane? Or is there any liquids at all involved in it?

No, they're generally about 1,200 BTU gas, so you've got good liquid content in there. We process virtually everything in that field.

Okay, thank you. That's helpful. And the other question is, what are you hoping to get out of the Eagleford JV? Are you looking for more drilling expertise? Or just are you -- or basically, are you planning on operating it or are you really looking more for capital dollars or someone else to operate it?

Well, I'd say there's really three things that we're focused on there. First of all, we have a very substantial position in South Texas in both the Olmos and the Eagleford. And we clearly want to implement our Olmos program. We believe it's very, very viable and part of our corporate strategy. None of that is on the table.

But as to the Eagleford, we want to get with that. So the first thing to consider here in a joint venture is, how can we accelerate that without diminishing our movement forward in the Olmos, as well?

The second thing is, obviously, we want the right kind of partner. We'd like a partner that will bring more than just a consideration to the table, but a partner that is good to work with, has some good technical experience. And we certainly are seeing that there's a lot of folks out there that would meet that criteria. And we're interested in that.

And of course, third, consideration is important. The nature of that consideration [from someone] in various ways such as cash, [carries], other thing; we're evaluating those types of things.

But I mean do you expect to be the operator or do you expect your JV partner -- if you're able to get one, to be the operator?

Well, we have a substantial position in South Texas. And given that we have over 500 wells in the area, we've worked with the land owners and we have all the infrastructure there. We intend to be the operator.

Fair enough. Thank you, gentlemen.

There are no further audio questions at this time. Are there any closing remarks?

Okay. We thank you very much for joining us today on our conference call. Thanks for your time and attention. Appreciate it.

This does conclude today's conference call. You may now disconnect your lines.