Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Paul Vincent - IR

Terry Swift - Chairman and CEO

Alton Heckaman - EVP and CFO

Bruce Vincent - President & Secretary

Bob Banks - EVP and COO

Analysts

Michael Hall - Wells Fargo

Joe Allman - JPMorgan

Adam Leight - RBC Capital

Leo Mariani - RBC

Andrew Coleman - UBS

Ray Deacon - Richard Capital

Biju Perincheril - Jeffries

Swift Energy Company (SFY) Q4 2009 Earnings Call February 18, 2010 10:00 AM ET

Operator

Good morning. My name is Robin [ph] and I will be your conference operator today. At this time, I would like to welcome everyone to the Swift Energy Fourth Quarter 2009 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. (Operator Instructions). Thank you. Mr. Paul Vincent, Manager of Investor Relations, you may begin your conference sir.

Paul Vincent

Good morning. I'm Paul Vincent, Manager of Investor Relations. I'd like to welcome everyone to Swift Energy Fourth Quarter 2009 Earning 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 fourth 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 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 projection 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.

We expect our presentation to take approximately 25 to 30 minutes and have allowed additional time for questions.

Terry Swift

Thanks Paul. Thank you all for joining our conference call today. We began 2009 in the midst of global economic downturn and a high level of commodity price uncertainty. Swift Energy was able to quickly adjust to a very difficult environment by keeping the cost levels of our operations under control and maintaining financial discipline. As energy prices improved and global credit markets opened up, we took decisive action to strengthen our balance sheet and strategically improve the company's growth opportunities. Through out 2009, we high graded our project inventory and consolidated our Eagle Ford [ph] and almost anchorage positions. During 2009, we also initiated strategic drilling activities to further appraise our South Texas opportunities. During the fourth quarter, two new horizontal wells were drilled in the Olmos formation in the AWP field in conjunction with the shallow, vertical drilling program and an ongoing refracture stimulation program.

The horizontal Olmos wells were completed and tested in January of this year and have been performing very well. During the fourth quarter of 2009, we also began drilling two Swift operated horizontal Eagle Ford Shale wells. One in McMullen County and one in Webb County. These wells have now concluded drilling operations. Vertical pilot holes were drilled to obtained cores from both these wells as far as their initial evaluation program. We expect to discuss what we've learned from this activity in greater detail at our annual analyst meeting next Thursday, February 25th in Houston, Texas.

Both of these wells are scheduled to be completed in March. Finally, we also participated in one well that is being drilled by Petrohawk under a joint venture agreement entered into during the fourth quarter. This agreement covers anchorage in McMullen County.

We expect this well to also be completed during the first quarter. Bruce and Bob will comment in greater detail in all of our drilling results and the operating highlights of the fourth quarter a bit later on. In November, we issued 225 million of eight, and seventh eights percent senior notes due in 2020 and called our $150 million, 2011, seven and five eights percent senior notes.

This offering moved our only near term potential debt maturity and removed our only near term potential debt maturity and allowed us to pay down all of our borrowings, outstanding on our credit facility. And help to prepare us financially for an expanded capital and operational program in 2010.

Alton will discuss this offering in greater detail in just a few minutes. Our 2010 announce capital expenditure budget of $300 to 375 million is expected to be funded through operating cash flows and cash on the balance sheet and is subject to pricing received in 2010.

We expect the spending level to deliver approximately 5% production growth. But more importantly we expect our daily production exit rate to be approximately 10% higher than the 25,100 net barrels of oil equivalent per day rate that we entered in 2010 with. We also expect to deliver 5% to 10% reserve growth in 2010. More importantly we expect this spending level to allow for predictable growth in both production and reserves in 2011 and beyond.

The majority of 2010 spending will be in our South Texas area dedicated to our Eagle Ford Shale and Olmos Tight Sand drilling programs and in our South East Louisiana area focused on maintaining and even growing slightly our own production levels there. We will update these estimates along with our guidance for the year as the year moves forward.

We will always remember 2009 as a difficult year that tested everyone in our industry and brought new opportunities. The challenges we faced with Swift Energy were met head on and resulted in a streamlined organization that is committed to improving performance and operating metrics while remaining focused on the bottom line and controlling cost to maintain appropriate margins.

During the fourth quarter of 2009 we strengthened our executive team and promoted three individuals; Randy Bailey to Vice President of Production, Steve Tomberlin to Vice President of Engineering and Barry Turcotte to Vice President of Accounting and Controller. The executive team together with our oil and gas professionals have worked diligently during 2009 to improve our performance and position the company for meaningful growth.

A cold winter and industry activity well below peak levels are supporting strip prices. These prices, we believe are very attractive for our plan 2010 project. We do appreciate that many market participants are forecasting weaker near term natural gas prices even while the remaining long term strip is very positive.

To protect our capital program against the sudden price decline, we have protected a portion of first and second quarter natural gas production with floors and continue to evaluate our price risk strategy to determine the best way to ensure minimum returns required for us to continue the scale of our activity particularly in South Texas.

While protecting against decreasing prices, we also monitored published data for elements of flattening or even decreasing natural gas production. Should we see this occur, Swift Energy is an excellent position to ramp up activity and capitalize in a strengthening commodity price environment.

This year, as we celebrate 30 years of doing business, we are in our history by being in the best position to deliver visible production and reserve growth that I've ever witnessed. I'm very excited to be working with the people and assets that we have assembled over the past several years and look forward to updating our stakeholders on our progress as the year continues.

And now I'll ask Alton to present our fourth quarter 2009 financial results.

Alton Heckaman

Thanks, Terry and good morning. The oil and gas sector continued to experience an improving environment during the fourth quarter of 2009. Swift Energy's financial results for the fourth quarter reflect this. Oil and gas sales excluding hedging effects were $115 million, a slight decrease from 4Q'08 was up 17% sequentially from the prior quarter.

Our income from continuing operations was $14.6 million or $0.38 per diluted share, up from 4Q'08 levels and beating current First Call main estimate. Excluding after tax debt retirement cost of $0.07 our 4Q'09 diluted EPS would be $0.45. Cash flow before working capital changes came in for the quarter at $2.10 per diluted share and 4Q'09 production was down from prior year levels, stayed flat sequentially from 3Q'09 at 2.2 million barrels of oil equivalent.

All in Swift's financial results for the fourth quarter were relatively strong. Natural gas prices for this quarter were 34% than 4Q'08 levels while crude oil prices were 28% higher. We lead to an overall 9% hot air price per Boe in 4Q'09. Swift's average realized price increased to $51.75 per Boe due primarily to crude oil prices increasing to an average of approximately $75 per barrel compared to approximately $59 per barrel a year ago. This was partially offset by natural gas prices declining by about $2 to an average of less than $4 per Mcf.

Quarterly oil and gas revenues increased 17% compared to the third quarter 2009 due to the increases in both crude and natural gas pricing. As Terry noted, we continue to focus on keeping the cost levels of operations under control maintaining our operating discipline and sustaining the reductions in our controllable per unit cost of metrics. Production came in above guidance for the quarter which further had to reduce our per unit cost in the following areas.

G&A for 4Q'09 came in at $4.16 per barrel within guidance. DD&A came in at $18.42 per Boe, below our guidance. Production costs came in within guidance at $8.85 per barrel. Interest expense came in at $3.63 per barrel, just slightly above guidance and production and ad valorem taxes came in below guidance at 9.6% of revenue, primarily due to final year end ad valorem taxes.

The result was income from continued operations for the quarter of $14.6 million which is $0.38, both basic and diluted. Excluding the ad valorem tax debt retirement costs of $0.07, our 4Q '09 diluted EPS would be $0.45 as I mentioned before. Our effective income tax rate for the quarter was $0.32 below guidance, primarily due to the realization of a capital loss carry forward that has previously been also with evaluation allowance.

Cash flow before working capital changes 4Q'09 came in at $79 million or $2.10 per diluted shares while EBITDA was $71 million for the quarter. Quarterly CapEx on a cash flow basis was $51 million. It was offset by approximately $26 million of joint venture proceeds related to our Eagle Ford joint venture activities. Let me now spend a moment to highlight Swift's solid financial position.

As Terry mentioned in November, we completed a very successful debt offering of $225 million eights and seven eights senior notes due 2020. The notes were issued slightly below par and the net proceeds were used to call our $150 million 2011 notes and pay down our line of credits.

Further, we closed our Eagle Ford joint venture which resulted in the receipt of $26 million. In addition to this upfront cash that we received, we also received $13 million in carried interest that would be applied to our shared drilling costs during 2010. I should note that the accounting rules actually require that the combination of these two amounts be reflected as a reduction to our 2009 capital expenditure.

With the decisive action we took in 2009 to strengthen our balance sheet including a very successful equity offering, we had no outstanding balance under our line of credit as of year-end 2009 and our net debt to equity ratio had been reduced below 40%.

With respect to our line of credit facility, with our 10-member bank group, it currently runs through October 2011, our borrowing base and commitment amount currently stands at approximately $277 million. The borrowing base was automatically adjusted downward from the $300 million by approximately $23 million due to our note offering in November being greater than the 2011 notes that they retired.

As we previously mentioned, we're emphatic about controlling our cost across the enterprise and even more emphatic about sustaining these cost reductions as prices improve. We continue looking closely at all our CapEx, operating and administrative expenses and we've identified several cost-saving opportunities in each of our core operating areas.

We continue working very closely with all our vendors for additional cost savings for goods and contract services. And as always, we will maintain a conservative financial discipline and have our 2010 CapEx budget that enables us to live within our cash flows and cash on hand while building some solid momentum throughout 2010.

We touch on Swift's hedging activity. We purchased floors covering a meaningful percentage of our domestic natural gas production for both, the first and second quarters of 2010, at an average NYMEX strike price close to $5per MMBtu that we continue to monitor once, through on a regular basis.

Please see our website for updates and complete and current information related to our hedging activity. We've also included additional financial and operational information in our press release including initial guidance for the first quarter and full year 2010. We feel we made all the right moves in 2009 during unprecedented times of uncertainty and adversity.

We entered the New Year with momentum. Swift is well positioned both financially and operationally to execute our long term growth strategy. We're excited about opportunities set and we're looking very forward to meeting the challenge in 2010 and beyond.

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

Bruce Vincent

Thanks Alton and good morning everyone. We appreciate you're listening in today. Today, I will discuss the fourth quarter 2009 activity including production volumes, recent drilling results, activity in our core operating areas and our plans for the first quarter of 2010. Bob Banks will then provide greater detail on significant operational successes of the quarter and their effects on our first quarter and full year 2010 plans.

Beginning with productions, Swift Energy's production during the fourth quarter of 2009 totaled 2.21 million barrels of oil equivalent or 13.29 billion cubic feet equivalent, above the mid point of our fourth quarter guidance as operational efficiency emphasize during 2009 continue to result in better performance throughout the company.

This improvement in performance is best illustrated by daily production rates. Our fourth quarter average daily production rate was 24,069 barrels of oil equivalent. Our average daily production rate entering 2010 was 25,100 barrels of oil equivalent per day.

Although daily drilling activity did increase during the quarter, the increase in daily rate is largely driven by an ongoing low cost production maintenance and enhancement programs. Fourth quarter production when compared to fourth quarter 2008 production of 2.47 million barrels of oil equivalent or 14.8 billion cubic feet equivalent decreased 10% primarily as a result of reduced spending and activity levels throughout 2009 along with natural declines. Sequential production was essentially flat when comparing the fourth quarter 2009 production to production in the third quarter of 2009.

For the first quarter of 2010 we expect production to decrease sequentially as a result of freezing problems due to the unusually cold temperatures and some unplanned equipment repairs at like Washington during the quarter. As Terry mentioned earlier we do expect to grow production by approximately 5% this year and our daily production rate to grow by approximately 10%.

For our fourth quarter drilling results, Swift Energy drilled 13 wells during the quarter. Two horizontal wells and six shallow vertical oil wells were drilled in the Olmos formation at the AWP field in McMullen County, Texas during the fourth quarter.

Two rigs have been active in South Texas during the first quarter with the Eagle Ford Shale as our objective. We're also participating in a well targeting Eagle Ford in our joint venture area with our partner in McMullen County. In the Lake Washington field as that compares to Louisiana, we drilled five wells targeting shallow and intermediate depth sands during the fourth quarter.

Two of these wells were completed and one was plugged and abandoned. One barge rig is continuing to operate in Lake Washington during the first quarter. I will briefly review our activity in each of our core operating areas for the quarter and Bob will detail the highlights of our more recent activity.

In the Southeast Louisiana core area which includes the Lake Washington and Bay de Chene field, production during the fourth quarter of 2009 averaged approximately 13,019 net barrels of oil equivalent per day or approximately 78 million cubic feet equivalent per day in this area. That's a decrease of 2% when compared to the third quarter of 2009 average net production from the same area.

Lake Washington averaged approximately 9,645 net barrels of oil equivalent per day or approximately 58 million cubic feet equivalent per day, a decrease of 4% when compared to the third quarter of 2009 volumes, primarily due to a slower pace of production maintenance activity and delays from freezing temperature and natural declines.

Bay de Chene's sequential production increased 2% to 3,374 net barrels of oil equivalent or approximately 20 million cubic feet equivalent per day as oil production which had been shut in as a result of damage caused by hurricane Gustav was online for the entire quarter.

Our initial 2010 operating plans called for one barge rig to be active in the area. Drilling locations involved Lake Washington and Bay de Chene throughout the year. In our South Texas core area, which includes AWP, Sun TSH, Briscoe Ranch and Las Tiendas fields.

Fourth quarter production averaged 7,192 net barrels of oil equivalent per day or approximately 43 million cubic feet equivalent per day. That was a 4% increase in production when compared to the third quarter of 2009 in the same area. This increase is primarily a result of the vertical drilling program in the vertical drilling program in the northern portion of AWP field and the ongoing refrac program in the same field.

In the AWP field located in McMullen County the R Bracken 36H and the AFP 1H Horizontal wells were drilled to the Olmos formation during fourth quarter. The R Bracken 36H was completed at the end of 2009 and the AFP 1H well was completed in January.

Both of these wells are flowing to sales currently and provide us with additional confidence in our ability to drill and complete high deliverability, economic horizontal wells in the Olmos formation. Bob will discuss what we've learned from these two wells in addition to our plans for the continuation of this program this year.

Also at AWP we drilled six wells in the Northern portion of the field during the fourth quarter. Four of these wells are currently producing with the remaining two wells expected to be producing to sales by the end of the quarter as they are tied into production facilities.

One additional well begin drilling in the fourth quarter and concluded drilling operations in January. This well has also been tied into production facilities and will be producing the sales by the end of the quarter. In addition to our drilling activity at AWP we continued an extensive refrac program in the field.

Swift Energy has also now drilled two wells targeting the Eagle Ford Shale as their objective. These wells began drilling operations in January. Both have a 100% working interest. We expect them both to be completed during the month of March.

Additionally the company has a 50% working interest in the first well being drilled the joint venture agreement with our partner in McMullen County. This well is also expected to be completed during the first quarter of 2010. Bob will spend time discussing these programs in greater detail.

The Central Louisiana East Texas square area which includes our Brooklyn, Maxis Creek and South Bearhead Creek Fields contributed 1,985 barrels of oil equivalent per day to approximately $11.9 million cubic feet equivalent per day of production in the fourth quarter of 2009.

There was no significant operational activity in this area during the quarter. And in our South Louisiana core area which is comprised of Horseshoe Bayou, Bayou Sale, Jeanerette, Cote Blanche Island and Bayou Penchant production rose to approximately 1697 barrels of oil equivalent per day or approximately 10.2 million cubic feet equivalent per day during the third quarter.

I will now turn the call over to Bob Banks to review operational highlights of the fourth quarter.

Bob Banks

Thanks Bruce. The four wells that were completed in our Lake Washington field were drilled to measure depths ranging from 6023 feet to 7240 feet and had an initial average production rate of approximately 350 gross barrels of oil equivalent per day each. This one rig program is designed to maintain stable production volumes at Lake Washington. This field is a tremendous mature asset which serves as an excellent cash flow source for our merging projects in South Texas that will require significant sustained capital spending levels over the next several years. Also, during the quarter at Lake Washington field, our production optimization program involving gas lift enhancements, asset stimulations and sliding sleeve shifts to change productive zones was continue to assist in the mitigation of natural field declines. During the fourth quarter, well work was completed on 11 wells and two re-completions were performed.

Average initial production from these operations was approximately 252 gross barrels of oil equivalent per day each. In the Bay de Chene field, the company is making preparations despite the well late in the first quarter; we're only in the second quarter of the year. Initial drilling will focus on oil development opportunities at depths between 11,000 and 12,000 feet so with energy plans to keep at least one rig operating in the Southeast Louisiana area during 2010.

In South Texas, at the AWP field, our horizontal Olmos drilling program now includes five completed wells. Recapping the performance of the first three wells drilled, the R Bracken 33H, our first well is the only well online now for over 12 months and its recovered over 1.1 billion cubic feet equivalent. Its current average daily rate is still over 1.5 million cubic feet of gas per day and ultimate recovery is now anticipated to be between four to five billion cubic feet equivalent. The 34H, the R Bracken 34H well, the least productive well on initial basis that we drilled in this program was expected to recover less than 3 billion cubic feet of gas but did serve as a valuable learning project for our South Texas asset team that can be just demonstrated by our most recent well results.

The third well, the R Bracken 35H which initially appeared to be a very strong well experienced a severe mechanical failure approximately five days after it was completed. We have diagnosed this as a parting in the production liner which is one of the risk associated with the completion approach used in this particular well design. The difficulties experienced in this well confirmed the need to refine our approach to the well construction and completion design that we use in these types of wells.

We have since employed premium to red connections and are now cementing our liners in place. We have also change the actual fracture stimulation technique through a first implied design as opposed to the open holes wellable packer design that was utilized in the first three wells of this program. We believe this change in process has reduced the risk of mechanical failure and allows for us to extend the reach of our laterals and potentially add more crack stages to our completion design in the future. We are back in 36H and the AFP 1H, all of the two most recent wells drilled in the program. Contemplated completion design was first use in R Bracken 36H which had a horizontal lateral of 3300 feet and 11 frac stages.

This well tested in a initial rate of a 11.5 million cubic feet per day with a flowing casing pressure of 5300 PSI on 20/64 inch choke. This well's production rate after 30 days was 9.9 million cubic feet per day with flowing casing pressure of 3800 PSI. We estimate that this well will ultimately recover close to 5 billion cubic feet of natural gas and has extended our field at least 2 miles to the South. We didn't drill a fine hole and collect core samples of the Olmos while we drilled this well. These core samples are being studied now and are helping us to refine and optimize our development drilling program in this part of the field.

The AFP 1H, our last well was also completed with first implied design and had a horizontal lateral of 4100 feet with 13 frac stages. This well tested in a initial rate of 6.4 million cubic feet per day and 280 barrels of common sate condensate per day 8.1 million cubic feet equivalent per day with a flowing casing pressure of 3500 PSI on a 24/64-inch choke.

After 30 days this well's production rate was 5.3 million cubic feet per day and 172 barrels per day of condensate or 6.3 million cubic feet equivalent per day with a flowing casing pressure of 2290 PSI. The condensate production from this well makes it a very high valuable well for us. We estimate that this well will recover between 4 billion to 5 billion cubic feet of gas equivalent.

The AFP 1H validates our most recent completion design and has extended our perspective field limit by at least two miles to the west. As we continue to delineate all this acreage that is perspective for this type of drilling, we expect our economics to continue to improve as costs come down and performance improves.

In the northern portion of the AWP field six vertical wells were drilled during the fourth quarter and one well concluded drilling operations in the first quarter. Since the third quarter of 2009 we have drilled eight of these wells in this portion of the field.

As an indicator of our continuously improving approach to our operations, the most recent well drilled, the Henry 2 was the fastest well that has ever been drilled in AWP field history. The results of this program were successful when viewed in terms of their impact on production. Field wide oil production has increased by approximately 300 gross barrels of oil per day since June and three of these wells are not yet tied into the production facilities.

We are also continuing our program of applying additional fracture stimulations to existing vertical well bores in the field. The average production rate after this operation is performed has been about 0.543 million cubic feet equivalent which equates to a 10% higher rate than the average initial production rates of the same wells when they were first completed. We have performed 29 of these procedures in 2009, beginning in September with an average cost of below $250,000 per well.

Finally, we did kick off drilling operations in the Eagle Ford Shale during the fourth quarter. We have drilled and are preparing to complete two wells that we have a 100% working interest in and one well, which is currently being drilled by our joint venture partner in which we have a 50% working interest. The capital spending program we announced earlier today accounts for having two rigs drilling on our 100% working interest acreage and one rig active in our joint venture acreage for the entire year.

Although it is too early to discuss the production and reserves impact on these wells for Swift Energy, we are encouraged by what we have seen so far. We expect to provide updates of all this activity quarterly during regularly scheduled conference calls throughout 2010.

We entered 2009 with a daily production rate of 25,100 net barrels of oil equivalent and we expect a 5% total corporate production growth for 2010. But equally or more importantly, we do expect at to 2010 with a daily production rate of approximately 20,500 barrels of oil equivalent and good momentum as we head into 2011.

Thanks for your attention at this morning. I'll turn it back to Terry to recap.

Terry Swift

Thanks Bob. Before we open the line for questions, I want to summarize Swift Energy's fourth quarter results and review some of our highlights from today's call. At Lake Washington, a drilling program is underway and our production enhancement and recompletion program continues. Drilling activity will also resume at Bay de Chene this year. We continue to strengthen our balance sheet and enhance our liquidity from a senior notes offering during the fourth quarter. Our shortest term maturity on any such obligation is now 2017.

Our capital expenditure budget of $300 million to $375 million funded through cash flows and cash on hand will deliver approximately 5% production growth and 5% to 10% reserve growth. We announced two results for two high rate horizontal wells on the Olmos formation, a tight gas sands formation that we've been drilling since 1989. These wells help to further de-risk our undeveloped acreage and provide additional data as to the potential of this asset.

We've now drilled two 100% working interest wells and one 50% working interest well in the Eagle Ford Shale. The log and core analysis information gathered thus far lead us to believe that these particular acreage positions are well suited for additional appraisal and development. We expect to complete and test these wells in March.

Finally we will be hosting our annual analyst meeting and Investor Day in Houston next Thursday, February 25th. Please see this morning's press release or contact our Investor Relations Department for details. At this time we'd like to begin the question and answer portion of our presentation.

Question-and-Answer Session

Operator

(Operator's Instructions). Our first question comes from the line of (inaudible).

Unidentified Analyst

Just curious as far as the Olmos. Maybe, you could give a little bit more color. What, when you resume the operations out there, in terms of what you are looking at in terms of rigs and half as many wells drilled this year, going forward?

Bob Banks

Yes. In terms is a question in terms of the Olmos?

Unidentified Analyst

Yes.

Bob Banks

Yes. In terms of the Olmos, we're really going to have two rigs for the full, well not for the Olmos but total, we'll have two rigs under contract for the year. One of those rigs, we expect to utilize pretty heavily for Olmos wells that we have kind of a mix to kind of an optimized strategy, how we are testing our Eagle Ford acreage position intermixed with some of Olmos development is a part of an optimized drilling schedule. So one of those rigs will be pretty heavily towards Olmos with some Eagle Ford. The other rig will be mostly towards the Eagle Ford.

Terry Swift

I would like to add to that at our analyst meeting, we are going to give a lot of detail about our actual program. So if you'll be patient with us next week, we'll be putting out a lot more detail.

Unidentified Analyst

Sure. That's helpful but I was just curious on that. And just in terms of rigs overall company wide, are they all pretty much contracted through the year just because especially in the Eagle Ford, it sounds like things will start to get a little bit more tight in that area. Just about wanted to make sure you have all lined up for the year.

Bob Banks

Yeah. For the wells and the Olmos and Eagle Ford, we have those lined up.

Terry Swift

The barge rig in southeast Louisiana, that's on a well-to-well contract basis. We don't. There's plenty of availability there. So we don't really need this long term contract. That one.

Operator

The next question comes from the line of Chris (inaudible) with Raymond James.

Unidentified Analyst

On the reserves, I was wondering if you give more detail on, when you saw that ads particularly on the gas side and from almost an Eagle for, in particular?

Bob Banks

Well, on the ad side, its, we don't have any in the Eagle Ford thus far in any of the numbers. What the ads that we had this past year, a lot of that came from this horizontal Olmos program.

Unidentified Analyst

Okay. Could you put any numbers around that?

Alton Heckman

I think we can discuss that a little more detail at the analyst meeting. But the drilling activity that we had during the year didn't even start till the second half and it really didn't begin in earnest of the fourth quarter. So in terms of new reserve development, it's primarily going to get it from the Olmos horizontal program that we had. We did not drill and complete any Eagle Ford wells. So we don't have any crude reserves at all in the Eagle Ford.

Unidentified Analyst

Okay. And how much did the last two Olmos well cost you? Sorry, I missed that.

Bob Banks

Our last Olmos well, we, our drilling guys are doing a great job in driving down the costs. We've eliminated the intermediate casing string now. We've also used an open hole or rotary stair hole assembly to kick off from a vertical position. So we've got our dry hole cost down in the order of $2.5 million to $3 million for the dry hole. Of course, depending on whether we drill pilot holes and cut cores and logs in all the rest. So, the dry hole costs really come down. Completion costs are probably in depending on how many stages, two and a half to three and a half whereabouts million dollars.

Unidentified Analyst

And just one last question. On the frac simulations, you're doing in AWP, what do you think and I don't know if I should look at this way that the 250,000 equates to in terms of added reserves. Should I just assume that its 10% more productive overall?

Bob Banks

Yeah. I think we have to try to dig through how much of that accesses additional reserves. We don't have that at our finger tips right now.

Terry Swift

For some of those wells, its not going to be an ad but in certain portions of the field, it does add. But I wouldn't consider that a material part in any reserve growth but whilst its important and very good economics.

Operator

Our next question comes from the line of Michael Hall with Wells Fargo.

Bruce Vincent

A few things. On the Olmos first, can you talk little bit more about way you thinking about inventory there? And on a similar line of questioning, what 37000 or so net acres? How much of that do you think have you tested at this point and are comfortable with in a control standpoint?

Terry Swift

I think again, we have to keep using this reserve in excuse for next. Next Thursday, we are going to have our analyst meeting and show maths and more detail, talk very specifically about acreage. And also next Thursday, we will be filling our 10K that has all sorts of data in it and we just, we won't be able go in to that information until we get all that filed. But I can say this, the horizontal wells have extended the field limit of the Olmos in, we believe materially south. And right now, we are seeing about two miles further south. They have also extended the field limits to the west and the southern portion of the field about a mile.

Now we do want to emphasize that you really can't treat Eagle Ford types of assessment the same way as Olmos. The Olmos does require that you actually have the sand there and present and so we're diligently mapping the sand. We definitely don't see this as a four county kind of play. So its not like Eagle Ford but its very, very important to Swift Energy Company because we've always been in the sand rich area of the Olmos sand and the AWP area and we believe we've buttoned up the vast majority of acreage that's necessary to extend this play.

Michael Hall - Wells Fargo

Appreciate it. Looking forward to next Thursday. Would you care to give future development costs and the reserve figures?

Bob Banks

Yeah that's going to be delineated more fully in the K.

Michael Hall - Wells Fargo

Just a little clarity on the growth commentary. Reading the release, it sounds like you exited 2009 at roughly 25000 barrels a day expecting 10% growth exit 2010 versus the exit 2009 right so implying at 27000?

Terry Swift

27,500, yeah.

Michael Hall - Wells Fargo

I didn't quite catch it on the call. Okay I'll wait for next week and look forward to seeing you.

Operator

Our next question comes from the line of Joe Allman with JPMorgan.

Joe Allman - JPMorgan

I just want to clarify in terms of the Eagle Ford Shale. So should we expect results from the first two wells in March?

Bob Banks

I don't think that we expect to complete them sometime in March. I wouldn't anticipate us announcing anything immediately. I think you want to, just like we showed in these results, we wanted a good 30 day number as well as your IP rates. I think that's more inductive of results.

Joe Allman - JPMorgan

And then is the first well on time or will that get delayed for any reason?

Terry Swift

JV well you're talking about?

Joe Allman - JPMorgan

Yeah, your first JV well.

Terry Swift

Well, obviously we're doing everything we can to accelerate the programs but also to make sure we're getting the right data and the joint venture relationship; we're very pleased with the way that kicked off. We have a actual joint venture operations team that works together and they're doing a little bit of science on this first well in terms of the way they're collecting data and we're pleased with the timing. Obviously we want to move things a little faster along but getting the right signs on the initial wells is very important.

Joe Allman - JPMorgan

In terms of reserves could you talk about the revisions and breakup it up by price and performance and further if you could, what part of the revision has proved developed versus prior?

Terry Swift

Again I think we're going to talk about that in detail, but they weren't significant.

Alton Heckman

Yeah. They weren't significant revisions.

Terry Swift

Yeah, but that's going to be filed in the Q and that's next Thursday. We've got to wait till we get that file.

Joe Allman - JPMorgan

And then just qualitatively in terms of the revisions, what were the drivers there? Was it price related and was it just PUDs getting removed or (inaudible) talk about qualitatively?

Terry Swift

Again, I guess kind of the guidance we give is there really wasn't anything unusual there, but really you have a mixture of a lot of things. Price was important. There were some performance issues but there are also some nice extensions in revisions upwards in some other areas.

Operator

Our next question comes from the line of Adam Leight with RBC Capital.

Adam Leight - RBC Capital

Some of my questions have been asked and some of those were actually answered. In your area of the Eagle Ford what's the expected liquids content and how does that vary across the plat for you?

Terry Swift

I'll take a shot at that and then let Bob follow up. We actually have what we believe are numerous or diversified Eagle Ford positions. Our Eagle Ford Position over in Webb County, we do believe that its going to be more of a dry gas. Its farther from the market. So in terms of adding significant production impact into 2010 this is going to have to go a little slower and more calculated?

As I move East and we get over in to our TSH Sun area we've got acreage that's really right on the reef or slightly behind the reef and we're waiting to see some of the first wells drilled but we anticipate that's going to be much oilier in that area.

As we move over to the AWP area where we've got excellent infrastructure and things can kind of move faster in terms of getting the market we have at least three different liquids areas that we see for the Eagle Ford, The down dip area, our most southern area which was principally not included in the joint venture. We see that as more of a dry gas and high pressure type environment.

So we're looking for some exciting results there. But again, that be dry gas we are expecting. As we move up into the fuel area proper, we're the joint venture as we see that more of a gas area with some nice condensate yield although, we don't expect it to really condensate. We think it will have gas, liquids in there. And there's every indication from data around us that it should be about risen.

In our northern AWP area which was not included in the joint venture, we're actually seeing some oil wells or very, very oily high condensate yield wells on strike to us. We're thinking that's going to be liquids. And we've got a nice acreage position there and north of the reef that could be extremely oily; really oil wells are very likely there as you get further north.

Adam Leight - RBC Capital

So. I don't have to quantify this but as you move towards your year end production reserves is in the mix of liquids, I guess its going to slow less than the implied by where you're drilling. Is that a sensible comment?

Terry Swift

Yeah. I think you would assume with the increased activity in South Texas, focused on the gas that our shift would be a little more gassy but obviously, the high liquid content and some of the stuff just like the AFP wells is a good example will help mitigate that. And then, that's one of the reasons we want to continue drilling unlike Washington is to keep that oil production content up. I mean for obvious reasons with the price sparing on BTU basis through liquids and gas.

Adam Leight - RBC Capital

I just want to clarify the exit rate versus the first quarter guidance on production and costs. How much of that is rather maintenance? And this seems to be sort of a large gap downward between what you are expecting average production. And then on the cost side, unit cost, how much to that is just really metric and how much to that is additional payments?

Terry Swift

Well, I wouldn't call a large gap. It's a small gap. We did have some very, very cold weather and we've tried to note what effect that had. It's very hard to peel that out but we actually had a lot of freeze ups there. Of course, you guys know how that big coal fronts came through. We also had some equipment down, unplanned equipment repairs and maintenance that we had to do out there. That has impacted our first quarter production. But in terms of the rates that we see, we clearly also have wells that are awaiting completion that or they have just come online that we think is restoring some very important momentum to us. So yes, there's kind of a little bit of a gap in that first quarter but we're very confident about the momentum we're building. And adding to the second part of your question relative to the per unit cost, it's almost entirely a volumetric thing. We feel very confident we can hit those full-year per unit metrics that we've guided.

Operator

Our next question comes from the line of Leo Mariani with RBC.

Leo Mariani - RBC

Good evening guys with two barrels of RBC here. Real quick just kind of continuing on the Eagle Ford, do you suggest the first two wells drilled this point in time that include the horizontal portion and just curious as to the joint times in those wells and how long does hold for?

Bob Banks

Don't have exactly the drilling times but I can give you that most of the laterals. Yes, both of the laterals were 3800 feet and both of these wells did have pilot holes where we drilled vertically through the base of the Eagle Ford, cut course, laying a full suite of logs, plugged backed and then kicked off the lateral. So these are what we would call evaluation wells or science wells to help us understand each of our different areas better. But clearly, the drilling guys did a great job. The, both of those wells, they drop that intermediate string and they use this open hole or rotary stair bore assembly where we drill those curves in about two and half days on both of those wells where a lot of operators and some of our early wells that currently it will take 6-7 days to build. Both of these wells, I can tell you came in significantly under our original AFP.

Leo Mariani - RBC

Okay. And I guess speaking with the Eagle Ford here, just curious as to whether or not; you guys have anything baked into your production guidance in '10 for Eagle Ford success?

Alton Heckman

Well, we do have obviously some production baked in, built in for Eagle Ford success and Olmos success but we risk that. We believe that we could have some substantial upside to the guidance we provided definitive upon how we perform that because the Eagle Ford is new and really just beginning the Olmos, you want to get into that and get some real performance before you get little more aggressive what your guidance is.

Bob Banks

And again, we keep saying this and I got to say again, next week, we are going to have our analyst meeting. We are going to show you a lot more detail. For those of you that are following the Eagle Ford already and you know what's happening out there, this probably old news but last year, this time, we really only had a handful of wells that were materially West of us in the Eagle Ford. And this year as we plan our programs and make our assessments we not only have a couple of penetrations that we've made with logs that we have in our hands, core data that we've accumulated but we also have wells that surround our AWP acreage position on both sides to the West and to the East even now that are successful wells we've got drilling that's going on North of us and we actually have drilling that's going on South of us.

Leo Mariani - RBC

And last one to here for you guys. The well that you plan to drill in your program here in the Eagle Ford node 10, you think that you will be able to keep those wells on production pretty quickly after fracing them?

Bob Banks

Well clearly all of the wells in the AWP area, we feel very good about those. We can get that outlet hooked up fairly rapidly. I think as Terry alluded earlier out in Webb County, in our (inaudible) area the infrastructure is a little less dense out there. So I think what we're going to have to do there is we're going to have to appraise that area a little bit to try to understand better how much in place and recoverable reserves we have and then make the appropriate marketing arrangements from there. Also the artesian wells area we feel pretty good about. We're going to show you all of these things, all of these market outlets, all the infrastructure Thursday of next week.

Operator

Our next question comes from the line of Andrew Coleman with UBS.

Andrew Coleman - UBS

I had a couple of questions on as you look at your activity for 2009 over in 2010, looking at South Texas, on the reserve replacement standpoint, I'm guessing that most actually that was drilled were probably PUDs and as you look at 2010, can you give me a rough breakdown what you would expect the drill that would be PUDs versus probable's?

Bob Banks

Andrew, let me just clarify. Did you say you thought most of what we drilled in '09 were PUDs?

Andrew Coleman - UBS

For South Louisiana.

Bob Banks

Only for South Louisiana?

Andrew Coleman - UBS

Right. I mean the South Texas should be mostly (inaudible).

Bob Banks

Right. Yeah, that's probably true and in South Texas we're really stepping out and developing new positions, new potential.

Andrew Coleman - UBS

And then I guess, looking forward that its fair to assume that the gas exposure would go up a little bit over the next few years assuming that the program in South Texas keeps ramping?

Bob Banks

Yeah. I think you could see that.

Terry Swift

I think that's fair.

Andrew Coleman - UBS

Okay and just had a comment earlier that with the extension is Olmos play if there is a second well that brought us about two miles to the south and it's a one mile to the west, is that right?

Bob Banks

Yes actually probably about two miles to the west as well, so two in two.

Andrew Coleman - UBS

So that's looking like four sections. So maybe possibly 20 wells on the acreage spacing?

Bob Banks

Yeah. And again, Andrew hopefully you'll be there Thursday. We're going to show you a lot of this next Thursday in the spacing and what we're thinking about the spacing between the Olmos and the Eagle Fords and we're seeing in those little differently right now but we'll give you a lot of detail next Thursday.

Andrew Coleman - UBS

Okay, the last two questions were. One I guess, looking at the 300 barrel a day increase that you guys got there in South Texas, how much of that come from Olmos wells? So how many Olmos wells did that include?

Terry Swift

That was all Olmos wells up in the Northern part in our oilier part of the field. I think that 300 barrels over a average came in about three wells. We have three wells we're getting ready to hook up now. So these are nice little projects again as I think we alluded about our drilling costs way down. So the costs are really in good shape and it's making good economic return for us up there.

Andrew Coleman - UBS

Okay, and then the last question was are you thinking about all of (inaudible) South Louisiana. How is the pressure maintenance kind a going? Do you guys still want an (inaudible) well there? Is that something you guys are still testing or you guys kind of moving the program over to primarily to shallow drill right now?

Terry Swift

Right now we're focused more on the shallow drilling. The pressure maintenance, we'll show you more on that Thursday again but we're spending more time making sure we efficiently drain the loads of sand in that new port area efficiently before we inject watering because of some of the more complex geology in that area.

Operator

Our next question comes from the line of Derrick (inaudible).

Unidentified Analyst

Just a few questions on the Olmos and Eagle Ford. Could you guys mention how many horizontal wells were booked year end on the Olmos?

Bob Banks

No, we didn't and I don't think we're ready to release that just yet.

Unidentified Analyst

Okay. And second on the Olmos based on (inaudible) work you've done on the deposition environment, could you offer any color on the amount of exposure you might have to the condensate this area than the southern part of AWP?

Bob Banks

Well, I have taken the exposure really, we can only really talk about it in terms of acreage at this point and we will do that next Thursday. We'll give a pretty good review of where our acreage is and those portions of acreage in the different parts of the trend.

Terry Swift

And I also think that window area is completely defined yet by the industry. There's still quite a bit of drilling that needs to take place to properly define the word that oil or condensate, condensate gas and then gas to our gas window actually switches.

Unidentified Analyst

Okay. On the Eagle Ford, could you guys offer any insight or maybe give acreage acquisitions strategies for 2010? Under acreage strategy for 2010?

Terry Swift

Well, we continue to work the play and continue to make offers for acreage. And every now and then, we're picking up some additional leaseholds but it's very competitive out there and acreage prices are very are highly variable. But they are still parts of the play as Bruce mentioned that we judge as unproven and yet we are seeing those acreage prices sometimes not reflecting with the improvements. So where we do find what we believe is perspective acreage, we're picking up but I wouldn't anticipate big, big changes in our acreage position based on what I'm seeing out there and the way of availability.

Unidentified Analyst

Okay. And are you guys making bets on any particular area?

Bob Banks

Well, I think we are spreading our debt. We've got what we really refer to as five different areas that we think are very well defined. And each one of them had very good attributes and we're in the process of testing those.

Operator

Our next question comes from the line of (inaudible) with Global Data.

Unidentified Analyst

I've got pretty long list of questions but I would ask you just a few I, problem I thought it might be time consuming to sit at. Now that we all know the crude prices have increased much above the previous year levels. But that didn't happen in case of the national camp. So when you guys go ahead next year I mean, in 2010 and 2011, in the case of Eagle Ford share, how do you see those natural gas prices affecting your strategy as to whether to go ahead with, in the production or just postponing it until these prices help you?

Bob Banks

If I understand the question correctly and just for everyone's benefit, there is some breaking up on the call. So we don't hear everything precisely. But it sounded like you were talking about how the impact of future oil and natural gas prices impact our strategy. Clear, they impact in a couple of ways. They impact in terms of cash flow available.

We have the store to expand cash flow and we would anticipate spending cash flow. So lower prices will affect the amount of cash flow you have for the program. They also can affect the economics we think that still currently the current strip today, fully supports the economics and the Eagle Ford and the Olmos.

We have always used various price per management strategies to help mitigate and provide some floor for downward price movements. And we will continue to look at our revise our price risk management strategies accordingly and something like they almost an Eagle Ford development that is much more predictable. And if there is prices stability you may want to consider in some form locking those prices in a little bit more positive way to help underpin your future cash flows and you're economics and we'll be looking at that.

Unidentified Analyst

Okay apart from this, I did want to know how would prioritize this development programs in 2010 and 2011 simply because you have got these production optimization programs going on and you have got the Eagle Ford coming out and you have got the South Louisiana program. So how do you prioritize these over time in terms of the capital budget and all this planning?

Bob Banks

I think clearly this year we have to evaluate all of our position in South Texas and Eagle Ford. This is a year of evaluation for us. So you will see a fairly strong portion of our budget going toward South Texas this year with a lesser but still materially important part of the capital towards South East Louisiana, in particular Lake Washington and Bay de Chene and in Lake Washington it will be a lot more shallow to intermediate drilling.

At Bay de Chene we do have some oil prospects that we want to drill there that would actually be reserve adds in number of those cases. So its all very important to our portfolio and to our performance. So we have to issue priority to all of it to run in parallel and we have our organization set up in such a way that we can run these things in parallel through different asset teams.

Unidentified Analyst

Okay, one last question to you guys. I don't see much difference in the guidance for this year's CapEx. Its not much. So why is it that way? Don't you think that given that you have got immense prospects in Eagle Ford and others, don't you think that you need to have a little more than what you have given in the guidance with regards to capital expenditures.

Bob Banks

As I had said earlier, while we've now drilled two Eagle Ford wells and we've got one of the joint venture, we've not completed any and we don't have any amount of production. So we do have surrounding wells that others have drilled but we need to understand how those are going to perform, how they are going to hold up and so we're obviously going into the year being a little on the conservative side in terms of what we think we can do in terms of production growth and as we have risked that activity. We believe that there is upside to our guidance but we need to go out and execute and perform before we put that into the numbers.

Alton Heckman

Yeah I think I'll add to that. There's a financial strategy on top of the operating strategy and of course we all know what we went through in late 2008 and 2009 and we took as we have said decisive measures last year to improve the balance sheet and position ourselves so that we can ramp up activity without taking undue financial risks. So we are monitoring these markets all year long and if we continue to have good gas prices and good oil prices and good results, of course we'll be increasing activity.

Operator

Our next question comes from the line of Ray Deacon with Richard Capital.

Ray Deacon - Richard Capital

Could you talk about was the well cost of this almost horizontal ramp kind of 5.5 million, is that to the right ballpark?

Bob Banks

Well, yeah. I mean on one of them, we, as I mentioned, the 36H, we drilled a vertical cord, the Olmos when we firstly launched flood backs. So that's a little bit more expensive. But yeah it would be fair to say that depending on how much science we do on an individual well and there will be more Olmos wells where we will want to cut core as we extend out further. On those areas where we don't do the science, you're probably down in the low five million range on those wells that you're doing a little bit more science on here, in the six to six and a half range I would say.

Terry Swift

Keep in mind that we're stepping out in our initial wells, both in terms of science and geography. And once you get to the point where you say okay, I'm ready to go into a manufacturing mode, there's a lot of cost savings you get in terms of how you actually drill your wells and how do you set up your completion jobs.

Ray Deacon - Richard Capital

Got it. And you had thought I think about trying to cut out the need for intermediate trade casing in some might say be as much as a million dollars. I guess did that work or?

Bob Banks

It worked exceptionally well. Yes. In fact, we're going to show on Thursday more opportunity. As Terry said as we start more towards moving manufacturing mode. I think we will show you some more opportunity where we can drive these efficiencies much further.

Ray Deacon - Richard Capital

Okay. Got it. And I guess, just in terms of overall returns from the play, given the oil in this sixth well, I guess could that I guess you need more data but I was just curious how much it can affect the equate the return or payback on the wells if you have liquids.

Bob Banks

Significantly and obviously that also pertains to the need for it. Of course, it's a function of weight and liquid content as you get in to the deeper higher price at Eagle Ford. Those tend to produce much higher rate. So we got a number of things going on there from the time value of money and economic perspective.

Terry Swift

And I'd also like to mention that we have been in AWP for 20 plus years and we understand the Olmos and the gas associated with very, very well. Even when we say high or even when we say dry gas, there is usually a high Btu content. And that means you usually get some nice processing liquids and other kinds of liquid that add to profitability.

Operator

Our next question comes from the line Biju Perincheril with Jeffries.

Biju Perincheril - Jeffries

Can you talk about service equipment available in South Texas? I've recently heard some tightness there.

Bob Banks

Well, here on the service side, I guess the question is that this tightening up or how's that going? I mean obviously as more and more rigs go in there and more and more fracs are put on wells and especially in this Eagle Ford, yeah, it does create some tightening. So what we've tried to do is set up strategic alignment and schedule so that people can work with us and we can work with them on how the schedule these cruise and frac equipment. And as I said earlier we have rigs lined up for the year. So I think we have our arrangements in place to secure the program that we want to execute but having said that, yeah it is tightening. There are more and more people and more and more rigs.

Terry Swift

I would add to that that we are still significantly as an industry above the peak levels we saw in early 2008. So we are seeing more vendors and more folks want to come into this area. There's following the money. So there's a good opportunity for new entrants in this area.

Biju Perincheril - Jeffries

Okay. So if you want to schedule a frac out today, is there a wait time or can you get that though fairly quickly?

Bob Banks

We actually work well in advance on our frac schedules and we have schedules brokered with our service providers where we have kind of a two way commitment of hitting a window of time around our frac schedule. So far that's been working pretty good.

Biju Perincheril - Jeffries

Okay, and then the two wells that you drilled in the Eagle Ford, can you say anything more about what properties or characteristics between the last (inaudible) field and the AWP field. How that varies there?

Bob Banks

Well I think I would like to reserve that a bit for the Thursday analyst meeting. We will show you some of that. Certainly there are differences but both are encouraging to us and we will give you a lot more color on that Thursday.

Operator

(Operator instructions). Our next question comes from the line of (inaudible) Zimmer Lucas

Unidentified Analyst

I just had a quick question regarding the high Btu and your midstream contracts and how are you guys going to be booking these reserves? Are they going to be post processing and what's like the top of the other contracts associated with the high BTU?

Terry Swift

First of all, the high Btu comment, AWP Olmos gas has always had a high Btu. It's typically been anywhere from the 1100 parts of the field up to 1250, 1300 Btu gas. We've dropped some of those liquids out right there in the field. So that's not a processing issue at all. Other parts of that Btu string, we've taken historically the plants in the area and we do get a net back arrangement as to how they're built and those kinds of things. We follow very precisely the rules of the SEC and really our engineers and reserve auditors have all that detail but its not a material difference how that's handled?

Unidentified Analyst

Just kind of a questioning like, are you guys going to take title to the NGL?

Terry Swift

Well, in terms of title of the NGLs we've title in the ground and again I think you have to look at every processing contract you have because you could write them differently. Sometimes you get a percent of the liquids as though you've got court title, but most of that that gas leaves your sales point. Really you want your commentary to have responsibility for effective title.

Unidentified Analyst

So I mean just like for example, on the Olmos, the one that had to compensate, the gas portion, what's the Btu associated with that gas portion?

Terry Swift

Its about 12 50.

Unidentified Analyst

Okay so that's basically a wet gas stream that you guys reported and if you were to strip out the NGLs associated with that wet gas? You get what I'm trying to say?

Terry Swift

Yeah, we report the NGL.

Unidentified Analyst

Okay, so you would report the NGLs?

Terry Swift

We do yeah, yeah.

Alton Heckman

'

Its in our reports

Operator

At this time there are no audio question.

Terry Swift

Alright, well thanks all of you for listening in. We appreciate it. We're certainly glad to be in 2010 and looking forward to it.

Operator

That does conclude today's conference call. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Swift Energy Company Q4 2009 Earnings Call Transcript
This Transcript
All Transcripts