SilverBow Resources Inc (SBOW) 2005 Q3 法說會逐字稿

Good morning, ladies and gentlemen, my name is Holly and I will be your conference facilitator today. At this time I would like to welcome everyone to the Swift Energy third quarter conference call. [OPERATOR INSTRUCTIONS] Thank you. It is now my pleasure to turn the floor over to your host to Mr. Scott Espenshade. Sir, you may begin your conference.

Thank you, Holly. Good morning, everyone. I'm Scott Espenshade, Director of Corporate Development Investor Relations. I'd like to welcome everyone to Swift Energy's's third quarter 2005 earnings conference call. Terry Swift, CEO, will provide an overview, followed by Alton Heckaman, our Executive Vice President and CFO, who will review the financial results for the third quarter, Joe D'Amico, Executive Vice President and COO, will cover our recent domestic activity, and the Bruce Vincent, President, will update our New Zealand operations. Terry Swift will then summerize before we open up to questions.

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 and our industry. These statements involve risks and uncertainties detailed in our SEC reports and our actual results could differ materially. We expect our presentation to take approximately 25 to 30-minutes and have allowed ample time for questions. With that I'd like to turn it over to Terry.

Thanks, Scott. Again thank you for joining this morning's conference call. We're pleased to report that we have just recorded one of our best quarter financially in the history of the Company. These results were obtained in spite of one of the most active and damaging hurricane seasons on record. The eye of Hurricane Katrina passed directly over Port Sulphur, Louisiana. Which is the shore base of our Lake Washington production. Hurricane Rita came in ashore south of our Brookeland and Masters Creek Fields impacted their production and our Cote Blanche Island properties. Many of our employees and their families were directly impacted by Hurricanes Katrina and Rita and suffered personal property losses.

These catastrophic storms created serious personal hardships for those that live and work in the region. Concern for their health and safety will remain our first priority. Fortunately all of our people were able to safely evacuate themselves and their families. Working together we were able to develop and safely execute our recovery plans. Needless to say, the hurricanes prevented us from realizing our original 2005 production targets. Yet in spite of these storms Swift has posted record financial results through the first nine months of 2005.

The Company was proactive in keeping the market and our investors updated on the damage assessments at our recovery progress through numerous detailed press releases during the past quarter. Prior to the storms we were on track to provide for a 10 to 14% increase in 2005 production. However, again, due to the hurricanes, the Company has now revised its projection to a 1 to 3% increase in 2005 production which would be 59 bcf equivalent to 60 bcf equivalent.

Let me cover some of the highlights of this morning's third quarter conference call and earnings release. Management beliefs that earnings are a primary metric for long-term shareholder value and we're quite proud of our track record. We had earnings of $0.92 per diluted share for the third [company corrected following the conference] quarter of 2005 and cash flow of $2.31 per share. Despite the loss of at least 2 to 3 full months of rig and facility upgrade activity, again due to the hurricanes, we expect to increase production in 2005 and plan to bring on additional production in 2006 which would bring us to approximately 14 to 18% increase in that production for 2006. I'll let Alton and Joe and Bruce deliver more of the details on the financial and operation items in their sections of this presentation.

The energy industry has been operating with very little spare capacity prior to the hurricanes. That spare capacity has essentially been capped in the gulf coast region making our industry operating conditions even tighter due to their hurricane effects. This is certainly led to more cost pressures. Swift is working hard to control these costs. Most of our rigs have extended contracts. But we understand that in this kind of commodity environment we must remain vigilant and keep an eye on prices and costs. While the commodity market has cooled recently during the past few days we are still tremendously excited and challenged by the environment. This is one of the best times a oil and gas company could find to operate in.

As I mentioned earlier, higher commodity prices have led to cost pressures, yet at the same time global growth in energy demand and the energy demographics have led to human resource constraints as well. And of course we hope that the leadership in Washington resist the urge to intervene with these natural supply and demand market based responses. The global economy continues to grow and the energy industry continues to satisfy the world market demand. I might note that even with the amount of shut in production and resultant higher commodity prices that were experienced in the third quarter the U.S. economy still recorded a healthy growth rate in the third quarter. Swift Energy is meeting the daily challenges just as we've met them for 26 years. I believe the Swift Energy Company has many important competitive advantage -- advantages relative to our peers, one of which is the quality and diversity of our proven and probable reserve base. As we continue our successful development and exploitation of these assets, our inventory of future drilling activities will become more fully understood, appreciated and valued in the equity markets.

Again as I mentioned this morning, we're extremely proud of the accomplishments of our company and our employees. Their efforts throughout the recent storms are certainly in large part the reason we're here to report these exceptional results. The corporate strategies and financial resources are in place at Swift Energy Company for other engineering and geoscience teams to expand through organic growth opportunities over the next several years. We're finalizing our 2006 plans, and looking forward to further capacity increases in Lake Washington.

We're looking forward to expand our seismic data footprint in South Louisiana. Specifically we're planning a 3D shoot over the Cote Blanche Island area. These items plus our diversified dilling portfolio position us for some very high impact projects over the next several years. Recent additions to our portfolio include the South Bear Head Creek acquisition which was announced in September and brings additional strategic opportunities to the Company. We expect to continue delivering value to our stake holders through consistent operating results. And of course, that begins with strategic plans and the efficient implementation of those plans.

With that I'd like to turn it over to Alton to present the quarter's financial results.

Thanks, Terry, and good morning, everyone. As Terry said, in spite of the unfortunate weather events we experienced, Swift still had a exceptional quarter. In fact it was the third best -- the best third quarter in the Company's history. Revenues were $100.9 million up 35% in 3Q, '04. Net income was $27.5 million up 95%. Diluted EPS increased 86% to $.92, while net cash flow provided by operating activities increased 85% and was $3.06 per diluted share. Production, impacted by the weather events, declined 3%, 13.5 bcfe.

Swift's domestic production decline due to the hurricanes and tropical storm was offset by an increase in commodity prices received and led the way for our great results. U.S. production actually declined 10% for the quarter when compared to 3 Q, '04 due to this deferred production.

47% of Swift's production during the third quarter was crude oil which in the current pricing environment is quite favorable. With a current weighting of crude oil Swift's average composite realized prices for the third quarter increased 40% to $7.48 per Mcfe. Domestic composite prices averaged just under $9.00 and New Zealand composite prices rose 48% to $4.41 per Mcfe. Oil and gas sales revenue therefore increased 35%.

As Terry mentioned our per unit cost and metrics were obviously adversely affected by the deferred production. Estimated results for the third quarter of 2005 G&A came in at $0.43 per unit, due to lower volumes and the required expensing of certain restricted stock grants. I should also note here Swift will begin expensing stock options in 2006 with the implementation of FAZ 123 R. ED&A per unit came in at $1.77. Production costs came in at $0.91 as certain fixed and hurricane related expenses were allocated over the lower production levels. Production taxes increased in tandem with higher prices in the production mix and interest expense came in at $0.46 per unit. Swift thus realized net income of $27.5 million. Which on a per share basis equates to $0.96 basic and $0.92 diluted, beating first call mean estimates for the 14th conservative quarter.

Cash flow before working capital changes for 3 Q, 05 came in at $68.8 million or $2.31 per diluted share while EBITDA was $73 million for the quarter, both well over the 2004 comparable amounts. The numbers for the nine month period ended September 30, were record setting with three straight excellent quarters as further detailed in our press release. Swift's bank line remains untapped. We had no borrowings at 9/30. Providing plenty of available capital for any value adding strategic opportunities.

With respect to Swift's hedging activities see the details of our price risks position as posted and updated on our website.

CapEx for the third quarter was $56 million, well below our cash flow, resulting in a further increase in our cash balances at quarter end which was $66 million. Our increased 2005 CapEx budget of $240 to $260 million, which does include the South Bear Head Creek acquisition, should remain well within our '05 cash flow projections. Our preliminary 2006 CapEx budget, as described in the press release, calls for an increase of 25% over our 2005 CapEx to $300 to $325 [company corrected following the conference] million which is expected to stay within our operational cash flow.

And as always we've included additional financial and operational information in our press release including guidance for the fourth quarter. And now I'll turn it over to Joe D'Amico for a overview of our domestic operations.

Thanks, Alton. Good morning, everyone. Today I plan to cover four items, third quarter domestic production, the South Bear Head Creek acquisition, the facility upgrades at Lake Washington and fuel status and resent drilling resulting in our domesticated areas.

Through the first nine months of 2005 Swift Energy had record production totaling 44.9 bcf equivalent an increase of 6% from 42.5 bcfe produced last year in the same period. Domestic production in the third quarter of 2005 decreased by 10% to 9.1 bcf equivalent compared with 10.2 bcfe produced in the same 2004 period and decreased 24% sequentially compared to 2005 second quarter production of 12 bcf equivalent. These year-over-year and quarter-to-quarter production decreases are directly a result of the shut in of production due to Hurricanes Katrina and Rita and occurred predominantly in Swift Energy's oil and natural gas fields located in Louisiana.

Swift Energy recently obtained an alternate outlet for natural gas production in its Lake Washington field and expects Lake Washington production to return to pre-hurricane rates in the near future. We have just completed the connection of the new CN3 production platform which will handle the field sour crude oil and begin to flow hydrocarbons through the new facility. This new production facility will increase the capacity of the handling sour crude oil from 5,000-barrels to 10,000-barrels of oil per day. All facility upgrades in Lake Washington are expected to be completed in early December which would increase total liquids through foot capacity by 50%.

Bay de Chene and Cote Blanche Island fields remain shut-in under going repairs necessitated by damage caused by hurricanes Katrina and Rita. With a combined shut-in production level of approximately 1,000-barrels of oil equivalent per day. Swift Energy expects to restart these two fields by year end 2005. Additionally, Swift Energy currently has one well waiting to be completed and two wells waiting to be connected in the Lake Washington area. We are currently drilling the BONI exploration prospect and expect to move the delineation well of the Newport prospect later this month.

As Terry mentioned earlier, Swift Energy signed a purchase and sale agreement for interest in the South Bear Head Creek Field in Beauregard Parish, Louisiana with a effective date of August 1, 2005. This acquisition is expected to close shortly. The total purchase price for this acquisition is approximately $24 million will be subject to typical closing conditions and post closing adjustments. South Bear Head Creek field is located in the Toledo Bend area approximately 50-miles south of Swift Energy Masters Creek field, and 30-miles north of Lake Charles, Louisiana.

Oil and gas are produced in South Bear Head Creek predominantly from the upper and lower Wilcox stands ranging from approximately 10,600 to 13,700 feet. The field also has production in the Confield stand at approximately 8,000 to 8,500 feet. It is a large east west trending anaclinal closure and has had accumulative production of over 4 million-barrels of oil equivalent. The field consists of approximately 5800 gross acres with a average net revenue interest of 78%. Swift Energy plans to initiate an exploration program in early 2006 to drill crude, underdeveloped and probable locations. Fracture stimulate several wells, enhance facilities and improve per unit operating costs. It is expected that Swift Energy's 2006 budget will include $8 to $12 million of Capital Expenditures in this field.

Swift Energy's successfully complete the eight of nine wells in the third quarter of 2005. Of these wells, seven were drilled domestically of which one was a development well successfully completed in the Lake Washington area, five were development wells successfully completed in the AWP Olmos area and one was a unsuccessful exploratory well in Lake Washington. The company has deferred ten to twelve domestic wells from our 2005 drilling program into 2006 due to lost rig time from the hurricane. Currently the Company has three drilling rigs operating in Lake Washington and also has a completion rig in Bay de Chene which will alternate between Bay de Chene, Cote Blanche Island and Lake Washington area through the rest of the year. The Company has also contracted for a fourth barge rig to work in these areas that'll be available for approximately two to three months during the first quarter of 2006. Additionally, the Company has a rig working at AWP Olmos area, another rig in the Garcia Ranch area in south Texas. Now I'll turn you over to Bruce to talk about our New Zealand operations.

Thanks, Joe. Good morning, everyone. I would like to cover several things regarding New Zealand this morning including our third quarter production, our drilling plans including the new Piakau discovery well as well as a 2005 exploration program update and lastly talk about the realized prices in New Zealand.

New Zealand accounted for 32% of total production with 4.4 billion cubic feet equivalent produced in the third quarter of 2005. This 17% increase from the 3. 8 billion cubic feet equivalent produced in the third quarter of 2004, was due primarily to a extra crude oil lifting in the third quarter of 2005 compared to the third quarter of 2004. And increased natural gas production from the Rimu/Kauri area. Production in the Rimu/Kauri area averaged just over 23.6 million cubic feet equivalent per day in the third quarter, a increase of 120% from the third quarter of 2004, mainly from the success of our activity in the Kauri sand.

At the TAWN fields, production averaged over 24 million cubic feet equivalent per day in the third quarter, down 20% from the third quarter of 2004 and up 4% from the second quarter of 2005, principally due to the Piakau North A1 well production which came onstream during the third quarter. These TAWN fields are expected to continue their inherent decline through 2005 although production in the TAWN area could see additional increased production if the Piakau discovery is successfully developed.

Our drilling activity in the second quarter did begin with the Tawa B1 exploration well which was recently P&A'd. Swift Energy New Zealand had taken this well deeper than originally planned but did not find commercial quantities of hydro carbons. We also drilled a delineation well of the Piakau North A1 discovery well up in the TAWN area. The Piakau North-A2 well was drilled to a depth of 11, 897 feet and did encounter the targeted Eocene aged sand and it is currently being evaluated. We had planned to take this well extensively down depth to see if we could encounter an oil- water contact to help determine potential reservoir size. It does appear that this well did find a oil-water contact in this well bore in the lower portion of the well. We are currently evaluating the well to see if we can make a successful completion in the upper portion of the sand.

As a consequence of finding a oil-water contact, the Piakau North A1 well has been shut-in pending the evaluation of this reservoir as a potential oil field with a gas tap. We shut the Piakau North A1 well in to preserve the pressure of the reservoir. We are currently drilling the Ahuroa South B1 well which is testing the same formation in the northern portion of the permit. The next wells in the exploration joint venture with Mighty River Power include the Goss prospect in our Waihapa field area and the Trapper prospect in the Ahuroa field area, both of these wells should begin drilling shortly. Both of these areas are part of the TAWN area and will not be finished drilling, though, until the first quarter of 2006. Swift Energy New Zealand is also participating in the Oru Number 1 well, which is a shallow, non operated exploration well in which we have approximately a 21% working investment. This well was sputed last week on petroleum exploration permit 38716 which is located just to the east of Swift Energy's Waihapa oil field.

In New Zealand, the sales price of our marquis blend crude oil averaged $61.23 per barrel, a 28% increase over prices for the same period last year. Swift Energy continues to see evidence of a strengthening in our natural gas realizations due to the supply and demand fundamentals in New Zealand. This has allowed Swift Energy New Zealand to tranche into natural gas contracts at the increasing market level. The fact that TAWN production is declining, which is under a older contract, and the Kauri gas is a increasing portion of the gas stream and under a newer contract, it allows Swift to typically realize a higher aggregate New Zealand dollar price each quarter. Currency exchange rates have reached a plateau much of this year, near $0.70 cents to the U.S. dollar which is slightly above the same period last year.

The natural gas price of $3.08 per Mcf for the third quarter, a 39% increase from the third quarter last year and a 1% increase over the $3.05 per Mcf received in the second quarter of 2005.

Year to date 2005, Swift Energy New Zealand has averaged $3.10 per Mcf for its gas sales. Additionally our contracts for natural gas liquids yielded an average price of $19.50 per barrel for the third quarter of 2005. Remind you that New Zealand natural gas and natural gas liquids price contracts are both denominated in New Zealand dollars. Swift Energy New Zealand's near-term exploration focus coupled with our development assets gives us a very competitive drilling portfolio to deliver targeted growth over the next several years. And Swift Energy's ten years in New Zealand we have built original expertise in the Taranaki basin, plus substantially infrastructure and onshore acreage to position us for success. Swift Energy New Zealand continues to focus our assets to aid the projected New Zealand natural gas shortfall that becomes more evident each year. Thanks for your attention. I'm going to turn it back to Terry for recap and then we'll have some Q&A.

Thanks, Bruce. To conclude before we open it up for questions let me remind you that we had earnings of $0.92 per diluted share for he third quarter of 2005 and cash flow of $2.31 per share. We're in an exceptional commodity price environment with strong fundamentals and the best internally generated opportunities set in our 26 year history. Through the third quarter of 2005 we've had impressive financial results and we intend to continue delivering on our operational plan for the remainder of 2005 and into the coming years. We have a high impact exploration program from South Louisiana to New Zealand and this program has the opportunity to deliver significant results to the Company.

We will continue to look for strategic acquisitions and complement our oil and gas expertise by utilizing our operating skill sets. We're encouraged by our progress in all of our core areas. Growth in Lake Washington and New Zealand should continue and additional growth should come in 2006 through our Bay de Chene and Cote Blanche Island activity.

We want to personally thank our investors and stake holders for their confidence in our abilities to recover from Hurricanes Rita and Katrina. We also want to commend our people for the courage and dedication that they displayed in one of the most damages hurricane seasons on record. Swift Energy Company has a strong and flexible financial position, has an exceptional organization of talented oil and gas professionals, and together we can accomplish many additional growth activities in the future whether they be growth through drilling or growth through strategic acquisitions. At this time I would like to begin the question and answer portion of our presentation.

[OPERATOR INSTRUCTIONS] We'll pause for just a moment to compile the Q&A roster. Our first question is from Adam Light of Credit Suisse First Boston.

Good morning, gentlemen.

Hey, Adam.

Morning.

Hi, Adam. How you doing?

I'm going to make this a hybrid question. On your '06 guidance could you provide us a basic break down by region and by type on the CapEx, and the same on the production growth?

Adam, we're not prepared to do that at this point in time. As you know, we generally provide the production guidance and the capital budget at the beginning of the year. But we thought that given the impact of the storms that it was important to go ahead and provide some preliminary production guidance as well as CapEx guidance and so we just did it kind of on a corporate basis.

Okay. You can't even make it a little bit generalized in trend?

Not at this time.

Okay. Then more specifically, a couple of dry holes in Lake Washington area, a little bit of color on -- was that at the edges of the formation, was there something different about those wells?

Adam, this is Terry. You know, we have a development and exploitation plan in Lake Washington that does anticipate some dry holes in the year. We actually factor that into our plan. Overall the program has been very successful. Joe's going to look up the stat here while I'm talking. But we have not had any change in how we would anticipate the overall dry hole rate out there. It had historically been between -- Joe's got the number there -- 75%. And we're sticking to that number.

I think bottom-line.

For successful wells.

There's nothing to read into that whatsoever. You go through periods of time, there's nothing unusual about those particular wells. The wells we're drilling are pretty much scattered around the dome. We expect to have some dry holes that's factored into all of our forecasts.

Okay. And just real quickly lastly, the third quarter New Zealand production the extra lifting, what does that do to fourth quarter.

I didn't hear the tail end of the question.

How much was the lifting?

Oh, how much was the lifting?

And does that effect the fourth quarter volume?

Yes, it does effect the fourth quarter slightly. We have these inventory issues every quarter. They're not significant in the scheme of things but they can vary quarter-to-quarter production. It will impact the fourth quarter slightly, but that's built into the guidance we've provided. I think the other thing impacting the fourth quarter that's already also built into the guidance is during the third quarter we had had the Piakau North A 1 well on production. We shut that in I think it was September 29th, I believe, but essentially at the end of the third quarter. We currently don't plan on producing that well during the fourth quarter until we determine whether this is a oil field with a gas cap or not. Assuming that it is, which we believe that it is, when you analyze the data if you produce that gas well early you would be leaving hydrocarbons in the reservoir you wouldn't be able to get out.

This is Terry. I'm going to speak on just a generalized basis and not with reference to exactly to the third quarter. But the liftings, they cycle from quarter-to-quarter. And just so that it's not miss understood, generally you can have anywhere from a 10 to 30,000-barrel difference from quarter-to-quarter depending on where that lifting is. So in the larger scheme of things, while I -- while we mention it because of its significance, I don't believe it's material.

Great. Thanks. I've overdone my quota.

Thank you. Our next question is from Frank Bracken of Jefferies.

Hi. One primary question, and it relates to Piakau. You won't tell us a lot, but you've got a well that's ostensible, reasonably crystal in that it's encountered gas and you now have a well that's establishing oil-water contact. Can you give us any handle on what kind of mapped aerial extent you have here that's been proven up by this second well bore?

Well, Frank, I appreciate your interest and your questions -- we do have a -- well that we think is pretty much right on top of the structure and that's encouraging and exciting for us. We do have a second well that was purposed to extend out quite a ways that we believe we found a oil- water contact. We're currently industry drilling a third well to the north will also be a important well and we're trying to evaluate the Piakau North A2 well, the one that found all our product, to see if we could make a commercial completion in the upper portion of that sand. We frankly just need to evaluate this discovery a little further before trying to build expectations out there. We believe after a little more work and in due time we'll be able to give you the information that you would like to have.

All right.

This is Terry. I'll give a little followup again to the complexity of the reservoir. We do have seismic coverage. It's too deep coverage across the area and it's very complicated seismic to interpret and there is some concern about compartmentilzation so that should help you in terms of why we're being a little bit cautious about the appraisal process.

I guess the other thing that I would mention is that not only are we encouraged by the prospect of this discovery but it also makes the other exploration wells that we're drilling gas, Goss and Trapper, of greater interest. So we'll just have to see how that plays out, though.

All right. Thanks.

Thank you. Our next question is coming from Van Levy of Dahlman Rose.

Good morning, gentlemen. How are you?

Fine, Van, how are you?

Good. I was hoping you could give me a little more clarity on Lake Washington. You mentioned there was a alternate outlet in October to 80% of pre hurricane levels. Can you discuss where that outlet is, how it works and then what are the steps that you need to complete to get the remaining 20% on line?

Yes, Van, this is Bruce. I'll be happy to answer that. The gas production in Lake Washington and the historic route has been through the Tennessee gas pipe line to the Wycoksty plant --liquids plant which processes the liquids out as I think many people know that plant was damaged in the storm and is currently down and not expected to be back up for sometime. And Tennessee gas pipeline compressor station in that area was significantly damaged and it took some time for them to get their pipeline up and running. What we were able to arrange is actually once Tennessee got their pipeline back in operation, that enabled us to take our gas to the west as opposed to the east where we were able to hook into the Discovery pipeline and take it up to a plant that's operated by Discovery. And we currently have a arrangement with them to transport our gas and process the liquids up there. With that, we're starting to bring Lake Washington back up to 100% of pre Katrina levels. So that contract is going to be in place until the by Wycostky plant is available to take the gas. So we're in good shape with regard to that.

Were there any cost disadvantages going to the west versus the east?

There is a cost disadvantage, but it's relatively small in the scheme of things. And it's insignificant compared to not being able to produce your gas.

Sure.

It's very small. I don't think you'll see it.

Okay.

But it is, obviously, but not big numbers.

Then the second question on Lake Washington I was hoping you could clarify for me most of your drilling has been done in the shallower zones. And you shot seismic to the mid and deeper zones. Can you kind of give us a tier of activity and kind of layout the game plan over the next year, year and a half or so by depth?

Van, this is Bruce again. If Joe wants to chime in here he can. But our program really calls for a mix of wells, both -- some shallow but more intermediate and some deep. And to some extent it has to do with which rig we're working with. One of the things that clearly happened to us in the last three months was we lost significant drilling time because of the two hurricanes. One of the rigs, rig 15, which was damaged in a minor way from Katrina had to go back in the yard and be refurbished and we just got it back. That happens to be one of the rigs that drills the deeper wells so we were essentially out of service for that one for I guess about two and a half months. The rig -- let's see, the 28?

28, yeah.

Yeah, 28 stayed in the field, wasn't damaged, it got back to work but it's also able to drill some of the deeper wells. And then the other one rig.

19.

19 had actually gone into the yard for some maintenance before Katrina so it was in the yard undergoing routine maintenance so it was able to come back out after we could get back out to the field after Katrina and it's generally drilling the shallow to immediate wells. We had not drilled too many shallow wells because of the constraints on the sour production capacity, with now the CM 3 production platform up and running, and we just really turned that on or are going through the commissioning process, but that's a fairly significant event because that doubles our sour crude processing capacity from about 5,000-barrels a day to 10,000-barrels a day.

And so that will enable us both to turn on some shut- in wells that have sour crude oil as well as go back and develop some of the shallower areas that we had laid off of because we were limited on processing capacity. The plan for 2006, which will layout much more detail early next year when we have our analyst meeting is going to be a mix of wells. We're going to drill some shallow, some intermediate and some deep as well as a couple of significant exploration prospects in the area.

Good. Thanks, Bruce.

Thank you. Our next question is coming from John Zaringer of Loomis Sales.

Adam Light covered my question by exceeding his quota. So thanks, Adam.

Thanks, John.

Thank you. Our next question is coming from Jeff Robertson of Lehman Brothers.

Good morning. Most of my questions have been answered as well. At Lake Washington, Bruce, can you update the status of the gas lift system? I was away a little bit when Joe was talking about that and not sure -- wasn't sure if you all had gotten that back up full running or what the time table on that might be?

I would be happy to do that. We do have it up and running but that's one of the areas where the facilities enhancement is going to bring significant improvement to it. In the CM 3 production platform, which is actually on a production barge that we built and moved out and essentially put in place on a permanent basis in the field, that also brought a new compressor with. We're just getting that compressor going. That will certainly aid the gas lift system. The other significant facility improvement, though, that is underway that we talk about being completed by early December or in early December is two new compressors that are going on the 6700 platform. Those are in place but they still need to get hooked up and still need to be tested and commissioned and brought on stream. All of that added compression will give us a much more efficient as well as increased level of gas lift throughout the field. And that's one of the things that will certainly enhance our about to increase production just from existing wells.

Bruce, will the efficiency improve or have a impact on your operating expenses out there?

It should have some, absolutely.

Yeah, this is Terry. There's no question that in terms of the efficiency to the gas lift system you'll see the cost go down per unit of lift gas. But one needs to remember that the wells that we will primarily be lifting are wells that do have a higher water cup, so you'll see a corresponding increase in some of our disposable costs. But it's all to bring more oil to the market.

One last question. At AWP Olmos where you have one rig running is there a case to be made for trying to increase activity levels there?

Well, one could argue that. But I think our current plan is to essentially keep that rig going you're going to see a similar level of activity in our '06 budget. Obviously in this kind of gas market those wells are very attractive. It's a nice long life field. We've always talked about the advantages of the action AWP field with regard to the Swift portfolio. We continue to have opportunities for development down there and it generates a significant amount of cash flow for us. And so you'll continue to see similar and activity but we also believe in diversifying our capital across the portfolio projects that we have as opposed to trying to concentrate in just one area.

Okay. Thank you, Bruce.

[OPERATOR INSTRUCTIONS] Our next question is coming from Monroe Helm of CM Energy Partners.

Thank you. I'm a little bit new to your story. Can you give me a better feel for what the gas production and oil production is respectively in Lake Washington? And I was just wondering if you're able to -- how you're getting the oil out of the field right now you mentioned that you're able to take the gas through a different outlet. I was wondering about the well situation.

Yeah, sure, Monroe. Lake Washington is largely oil production. It's probably 95% oil production. The oil is actually transported out of the field in two different ways. There is a pipeline, the empire pipeline or Imco pipeline which is owned by Exxon which is operational at this point in time and there is also a barging transportation where we barge stuff out.

And generally we probably barge close to 50% of the production and transport about 50 through the pipeline. The market we take the crude oil to with the barges actually gives us an slight premium to the market that we ship through the pipeline that net against the added cost of barging really make it about the same. So it just provide us a really good diversified market. Sometimes we'll have different purchasers as well so you have a diversification in terms of your product purchasers as well.

And just as an follow up, I think you said that the production is going to be up to 80% of pre hurricane activity by what point in time?

No. What we said is it actually has been up to 80% pre hurricane levels. Now that we've established a gas market -- the reason it was limited was because we didn't have a gas market or actually weren't able to process -- transport our process, our natural gas. We've now just recently arranged for transportation and processing at a different plant and so we're taking it back up to the 100% of pre hurricane levels. That is also, of course, influenced by these facility upgrade that are going on. That until you get those things in place -- as you install them you limit production a little bit as you're going through commissioning process you're not getting full production. But we're bringing them back up to 100% of pre Katrina/ Rita levels now.

Okay. Thanks very much.

Thank you. Our final question is coming from Derek Van Zoren of Goldman Sachs.

Hey, guys. How are you?

Good, Derek. How about you?

All right. A question on '06 CapEx. I know you didn't want to go too far with Adam. But are you looking like you're going to have to add a lot more rigs or is the increase because of service costs? Can you give us a little handle on that at all?

It's probably a little of both. I would tell you it's more service cost related. We have extended contracts for three of the barge rigs that work in Lake Washington, Bay de Chene, Cote Blance Island and the southern Louisiana area. I would tell you it's really mostly drilling costs.

This is Terry. I'd also like to add that we will be drilling deeper wells. And with higher impact targets next year. Both in the development exploration side and on some of the exploration side. So some of that detail we'll be bringing forward early next year. But that's one of the reasons the costs will be higher.

Perfect. And you guys thinking about coming up in January-February? Like you usually do?

Well, we've not finalized our plans or analyst meeting but we're going to be doing that shortly and we'll announce that when we do.

Good. We'll look forward to seeing you, thanks.

Thank you. I thank every one for joining the call.

Are there any other questions?

Sir, we do have two follow ups . Would you like to take them?

Yes, we would.

Thank you. Our follow up question is coming from Monroe Helm of CM Energy Partners.

I might have missed this in your presentation but have you put any hedges on given the run up in commodity prices that we've had?

Monroe, it's Bruce again, our pricing management strategy or hedging strategy has consistently for many years resolved around trying to protect the downside without taking the upside. We generally implement that through the purchasing floors, sometimes participating colors. We've not added significantly to our price management position, though, in the last couple of months. We do post the details of all these transactions on our website. If there are new transactions in the recent time frame we try to include them in the press release. As you would note there were none listed which means we don't have any very short-term transactions of late.

Okay. Thank you.

Thank you. Our next question is a follow up coming from Van Levy of vowel man rode.

Book keeping question here. Do you have the pre hedged oil and gas prices or alternatively any hedged oil and gas losses byproduct?

This would be in the third quarter, Van?

Yes.

I would tell you that it's really not anything significant as far as the adjustment of the third quarter relative to hedging.

Okay. And last question, acquisitions, prices are beginning to come down a little bit. Obviously your Cote Blanche Bay and Bay de Chene were your last two. Can you give us any sense of what's going on in the marketplace?

Well, it's a interesting marketplace as I think we all know and we're certainly actively looking. We have announced the South Bear Head Creek acquisition in the upper and lower Wilcox which it should close fairly in the near future. We continue to look at other transactions. There is always kind of a rush for year end deals usually on the part of the sellers. As a buyer we don't have a need to do something by year end, but sometimes that makes for an ability to get something done when people have deadlines. So we're looking at things. But as always, we're going to try to be very selective, look for acquisitions where Swift has a competitive advantage, look for properties that we think that we could significantly exploit and add value to and build into potential core areas.

And in terms of bank availability and drawn, what kind of dry powder do you have now?

Lots of dry powder. We've got a borrowing base of $250 million. We've not sought any increase in that because we haven't felt a need for. We've got zero outstanding. We currently would anticipate having cash on the balance sheet even at year end. So we're in real good shape there.

Right. Thanks, Bruce.

Gentlemen, there are no further questions.

Great. Thanks.

Thank you for joining us today.

Thank you. This does conclude today's Swift Energy conference call. You may now disconnect.