SilverBow Resources Inc (SBOW) 2009 Q4 法說會逐字稿

Good morning. 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.

Good morning. I'm Paul Vincent, Manager of Investor Relations. I would like to welcome everyone to Swift Energy's fourth quarter 2009 earnings conference call. On today's call, Terry Swift, Chairman and Chief Executive Officer will provide an overview. Alton Heckaman, Executive Vice President and Chief Financial Officer, will review the financial results for the fourth quarter. And then Bruce Vincent, President, and Bob Banks, Executive Vice President and Chief Operating Officer, 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 Andland.

Before I turn it over to Terry, let me remind that everyone our presentation will continue forward-looking statements based on our current assumptions estimates and projections about us, our industry, and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports to which we refer you along with cautionary statements contained in our press releases, and our actual results could differ materially. We expect our presentation to take approximately 25 to 30 minutes, and have allowed additional time for questions.

Thanks, Paul. Thank you again for joining our conference call today. We began 2009 in the midst of a 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 improves and global credit markets opened up .we took decisive action to strengthen our balance sheet, and improve the company's growth opportunities. Throughout 2009 we high graded our project inventory and consolidated our Eagle Ford and Olmos acreage 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 to the Olmos formation in the AWP need 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, 2009, we also began drilling two Swift operated horizontal Eagle Ford shell wells, one in McMullen County and one in Webb County. These wells have now concluded drilling operations. Vertical pilot holes were drilled to obtain cores from both these wells as part of their initial evaluation program. We expect to discuss from what we have learned from this activity in greater detail at our analyst meeting next Thursday February 25th in Houston, Texas. Both of these wells are schedule today be completed in March.

Finally, we also participated in one well that is being drilled by Petrohawk under a joint venture agreement entered in to in the fourth quarter. This agreement covers acreage in McMullen County. We expect this well to also be completed during the first quarter. Bruce and Bob will comment in greater detail on all of our drilling results and the operating highlights of the fourth quarter a bit later on.

In November, we issued $225 million of 8% and .78% senior notes due in 2020. And (inaudible) our $150 million 211 7.58% senior notes. This offering removed our only near-term potential debt maturity, and allowed us to pay down all of our borrowings outstanding on our credit facility. And helped 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 announced capital expenditure budget of $300 million 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 this spending level to deliver approximately 5% production growth. But more importantly, we expect our daily production exit right to be approximately 10% higher than the 25,100 net barrels of oil equivalent per day rate that we entered 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 spend will be in our South Texas area, dedicated to our Eagle Ford shale and Olmos Tight Sand drilling programs, and in our Southeast Louisiana area, focused on maintaining and even growing slightly our oil 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 at Swift Energy were met head on and resulted in a streamline 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 planned 2010 projects. We do appreciate that many market participates are forecasting weaker near-term natural gas prices even while the remaining long-term strip is very positive. To protect our capital program against a sudden price decline, we have protected a portion of first and second quarter natural gas production with floors, and continued to evaluate our price risk strategy to term 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 monitor published data for evidence of flattening or even decreasing natural gas production. Should we see this occur, Swift Energy is in 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 honor our history by being in the best position to deliver visible production and reserve growth that I have 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.

Okay. Thanks, Terry. And good morning. The oil and gas sector continued to experience an improving environment during the fourth quarter 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 2008, but 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 2008 levels, and beating current first call mean estimates. Excluding after tax retirement costs of $0.07, our 4Q 2009 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 2009 production, though down from prior year levels stayed flat sequentially from 3Q 2009 at 2.2 million barrels of oil equivalence. All end, Swift's financial results for the fourth quarter were relatively strong.

Natural gas prices for this quarter were 34% lower than 4Q 2008 levels, while crude oil prices were 28% higher, leading to an overall 8%, excuse me, 9% higher price per BOE in 4Q 2009. Swift average realized price increased to $51.75 per BOE due primarily to crude oil prices increases 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 declines to about $2 to an average of less than $4 per NCF . 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 our operations under control, maintaining our operating discipline, and sustaining the reductions in our controllable per unit cost and metrics. Production came in above guidance for the quarter, which further helped to reduce our per unit cost in the following areas. G&A for 4Q 2009, 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 (inaudible) taxes came in below guidance at 9.6% of revenue, primarily due to final year-end (inaudible) tax true-ups. The result was income from continuing operations for the quarter, of $14.6 million, which is $0.38 both basic and diluted. Excluding the after-tax debt retirement costs of $0.07, our 4Q 2009 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 had previously been offset with a valuation allowance. Cash flow before working capital changes for 4Q 2009 came in at $79 million, or $2.10 per diluted share, while EBITDA was $71 million for the quarter. Quarterly CapEx on a cash flow basis was $51 million, but was a offset by approximately $26 million of joint venture proceeds related to our Eagle Ford joint venture activities.

Let me now spending a moment to highlight Swift's solid financial position. As Terry mentioned in November we completed a very successful debt offering of $225 million of 8% and .78% 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 credit. Further we closed our Eagle Ford joint venture which resulted in a receipt of $26 million.

In addition to this up front cash that we received we also received $13 million in carry interested that will be applied to our shared drilling cost during the 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 expenditures.

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 ten member bank group that 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 of 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 of our vendors for additional cost saving 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.

Let me 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 $5 per MBTU. And we continue to monitor that on a regular basis. Please see our website, for update and complete current information relative to our hedging activity. We also have included additional financial and operational information in our press release, including initial guidance for the first quarter and full year 2010. We feel we have made all of the right moves in 2009 during unprecedented times of uncertainty and adversity. We'll enter the new year with momentum.

Swift is well positioned both financially and operationally to execute our long-term growth strategy. We're excited about our opportunity 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

Thanks, Alton and good morning, everyone. We appreciate you 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 effect on our first quarter and full-year 2010 plans.

Beginning with production, Swift Energy's production during the fourth quarter 2009 totaled 2.21 million barrels of oil equivalent or 13.29 billion cubic feet equivalent, above the midpoint of our fourth quarter guidance as operational efficiencies emphasized during 2009 continued to result in better performance throughout the Company. This improvement 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 was largely driven by on ongoing, low-cost production, maintenance and enhancement program.

Fourth quarter production when compared to fourth quarter 2008 production of 7 million barrels of oil equivalent or 14.8 billion 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 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 Lake 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 6 shallow vertical 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 sale as our objective. We're also participating in a well targeting the Eagle Ford in our joint venture area with our partner in McMullen County. In the Lake Washington field in Blackman Parish in Louisiana, we drilled five wells, targeting shallow and intermediate depth sands during the fourth quarter. Four of these wells were completed and one was plugged and abandoned. One barge rig is continuing to operate in Lake Washington during the fourth 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 fields, production during the fourth quarter of 2009 averaged approximately 13,019 net barrels of oil per day or approximately 78 million cubic feet equivalence per day in this area. That's a decrease of 2% when compared to the third quarter 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 2009 volumes, primarily due to a slower pace of production activity and delays from freezing temperatures and natural declines.

Bay de Chene sequential production increased 2% to the 3,374 net barrel of oil equivalent or approximately 20 million cubic feet equivalent per day as oil production which has 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 in both Lake Washington and Bay de Chene throughout the year. In our South Texas core area, which includes AWP, Sun TSH, Briscol Ranch and Las Tiendas field fourth quarter production averaged 7,192 net barrels of oil equivalent per day or approximately 43 million cubic feet of oil per day. That was a 4% increase in production when compared to the third quarter 2009 in the same area. This increase was primarily the result of the vertical drilling program in the northern portion of the 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 the fourth quarter. The R Bracken 36H was completed at the end of 2009, and the AFH 1H well was completed in January. Both of these 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 learned from these two wells in addition to our plans for the continuation of this program for 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 per sales by the end of the quarter as they tied in production facilities. One additional well began drilling in the fourth quarter and concluded drilling operations in January. This well is also being tied in to production facilities and will be producing to 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 our objective. These wells began drilling operations in January. Both have 100% working interest. We expect them both to be completed during the month of March. Additionally the Company has the a 50% working interest in the first well being drilled under 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 be discussing these programs in greater detail.

The central Louisiana, East Texas core area, which includes our Brooklyn, Master's Creek, and South Bear Head Creek fields, contributed 1,985 barrels of oil equivalent per day or 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 Horse Shoe Bayou, Bayou Sally, Jeanerette, Cote Blanche Island and Bayou Penchant production averaged approximately 1,697 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.

Thanks, Bruce. The four wells that were completed in our Lake Washington field were drilled to measured depth ranging from 6,023 to 7,240 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 an excellent cash flow source for our emerging 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, a production optimization program involving gas-lift enhancements, absent stimulation, and sliding sleeve shifts to change productive zones was continued to assist in the mitigation of natural field declines. During the fourth quarter, well work was completed on 11 wells, and two recompletions were performed. Average initial production from these operations was approximately 250 gross barrels of oil equivalent per day each.

In the Bay de Chene field, the company is making preparations to spun a well late in the first quarter or early in the second quarter of the year. Initial drilling will focus on oil and development opportunities at depths between 11,000 and 12,000 feet. Swift 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 only well on line now for over 12 months and has recovered over 1.1 billion cubic feet equivalent. It's 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 4 billion to 5 billion cubic feet equivalent. The 34H, the R Bracken 34H well, the least productive well on the initial base that's we drilled in this program is 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 as can be 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 of the production liner, which is one of the risks associated with the completion approach used in this particular well design. The difficulties experience in the well confirmed the need to refine our approach to the well construction and completion design that we used in these type of wells. So, we have since employed premium thread connections and are now cementing our liners in place. We have also changed the actual fracture stimulation technique to a perk and plug design as opposed to the open hole swellable packer design that was utilized in the first three wells of this program.

We are believe this change in process has reduced the risk of mechanical failure and allows for us to extent the reach of our laterals and potentially add more frac stages to our completion design in the future.. The R Bracken 36H, and the AFP 1H, all the two most recent wells drilled in the program. Perk and plug completion design was first used in the R Bracken 36H, which had a horizontal lateral of 3,300 feet and 11 frac stages. This well tested at an initial rate of 11.5 million cubic feet per day with the flowing casing pressure of 5,300 PSI on a 20-64 inch choke. This well's production rate after 30 days was 9.9 million cubic feet per day with flowing pressure of 3,800 PSI. We estimate this well will ultimately recover close to 5 billion cubic feet of natural gas and has extended our a field at least two miles to the south. We did drill (inaudible) and collect core samples of the Olmos sand while we drilled this well. These core samples are being studied now, and are helping us to refine and optimize our developing drilling program in this part of the field.

The AFP1H, our last well was also completed with the perk and plug design and had a horizontal lateral of 4,100 feet with 13 (inaudible). This well tested at an initial rate of 6.4 million cubic feet per day and 280 barrels of condensate per day, or 8.1 million cubic feet equivalent per day, all with a flowing casing pressure of 3,500 PSI on 24 64 inch choke. After 30 days this wells 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 2,290 PSI.

The condensate production from this well makes it a very high valuable well for us. We estimate this well will recover between 4 billion to 5 billion cubic feet of gas equivalent. The AFP1H 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 Olmos acreage that is perspective for this type of drills, 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 approving approach to our operations, the most recent well drilled, the Henry Number 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 in to the production facilities.

We are also continuing our program of applying additional fracture stimulations to existing virtual 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 that's 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 of these wells for Swift Energy, we are encouraged by what we have seen so far. We expect to provide updates of all of this activity quarterly during regularly scheduled conference calls throughout 2010. We entered 2009 with a daily production rate of 25,100 net barrels equivalent. And we expect a 5% total corporate production growth for 2010, but equally, or more importantly, we do expect to exit 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 this morning. I'll turn it back to Terry to recap.

Thanks, Bob. Before we open the line for questions, I want to summarize Swift Energy's fourth quarter results, and review some of the 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 continued 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 a 5% to 10% reserve growth. We announced two results for two high-rate horizontal wells in the Olmos formation, a tight gas sands formation that we have 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 have 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 would like to begin the question and answer portion of our presentation.

(Operator instructions). We'll pause for just a moment to come pile the Q&A roster. Our first question from the line of Jason Wringler with (inaudible) Securities.

Good morning, guys. Nice quarter.

Thanks, Jason.

Just curious as far as the Olmos and maybe just to get a little bit more color, when you resumed the operations out there in terms of what you are looking at in terms of rigs, and maybe wells drilled this year going forward?

Bob, you want to take that.

Yes, in terms -- is the question in terms of the Olmos?

Yes

In terms of the Olmos, well, not for the Olmos, but in 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, kind of an optimized strategy of how we're testing our Eagle Ford acreage position intermixed with some of our Olmos development as 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.

I would like to add to that that at our analysts meeting we're 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.

Sure. That's helpful, though. Just in terms of rigs overall company wide, are they all pretty much contracted through the year just because especially Eagle Ford sounds like things are starting to get pretty tight that area. Just wanted to make sure you have it all lined up for the year.

Yes, for the wells in the Olmos and Eagle Ford, we have those all lined up.

Thanks, guys.

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

That makes sense. Thanks, guys. We'll see you next week.

Your next question comes from the line of Chris LaChoy with Raymond James.

Good morning, guys. Congratulations on a great quarter.

Thanks.

On the reserves, I was wondering if you could give more detail where you saw the adds particular on the gas side and from the Olmos and Eagle Ford in particular.

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

Okay. Could you put any numbers around that?

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

Okay. And how much did the last two Olmos wells cost? Sorry if I missed that.

The last Olmos well? Our drilling guys are doing a great job in driving down the costs. We have eliminated the intermediate casing string now. We have also used an open-hole rotary stair ball assembly to kick off from a vertical position. So, we have got our dry hole costs 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 and all of the rest. So the dry hole costs really come down. Completion costs are probably in depending on how many stages, $2.5 million to $3.5 million there abouts.

And just one last question on the frac stimulations you doing in AWP, what do you think, I don't know if I should look at it this way, the 250,000 equates to in terms of added reserves. Can I just assume it's 10% more productive overall?

Yes, I think we would have to try to dig through how much of that access is additional reserves. We don't have that at our fingertips right now.

Yes, for some of those wells, it's not going to be an add, but in certain portions of the field, it does add. But I wouldn't consider that a material part of any reserve growth, though it is important -- and very good economics.

Thank you.

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

Thanks. Congratulations on a good quarter.

Thanks, Michael.

Thanks.

Let's see a few things. On the Olmos first, can you talk a little bit more about kind of the way you are thinking about inventory there? And then a similar line of questions. You have what 37,000 or so net acres. How much of that do you think is, have you tested at this point and are very comfortable with from a control standpoint?

I think, again we hate to keep using this as though it's an excuse, but next Thursday we are going to have our analysts' meeting, and show maps in more detail, talk very specifically about acreage. And also next Thursday, we'll be filing our 10-K that has all sorts of data in it. And we don't be able to go in to that information in we get all of that filed. But I can say this, the horizontal wells have extended the limit of the Olmos sand we believe materially south. And right now we're saying about two miles further south. They also have extended the field limits to the West in 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 assessments 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 it's not like the Eagle Ford, but it's very, very important to Swift Energy Company because we have always been in the sand-rich area of the Olmos sand and the AWP area. And we believe we have buttoned up the vast majority of acreage that is necessary to extend this play.

Okay. Appreciate it. Looking forward to next Thursday. Would you care to give future development costs on the reserve figures or we have to wait for that too?

Yes, again, that's going to be delineated more fully in the K.

Alright. If I may, just a little clarity on the growth commentary, reading the release, it sounds like you exited 2009 at roughly 25,000 barrels a day, expecting 10% growth exit at 2010, versus exit 2009, right? So implying a 27,000 --

27,500.

Okay. Didn't quite catch it on the call there. Okay. I guess I'll just wait for next week. And look forward to see you all. Thanks.

Thanks, Michael.

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

Thank you. Good morning, everybody.

Good morning.

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

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. Think that's more predictive of the results.

That's helpful. And the first well is that on time? Or is that delayed for any reason?

The first JV well you are talking about?

Yes, I'm sorry, the first joint venture well, yes.

Well, obviously we're doing everything we can to accelerate the programs, but also 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 an actual joint venture team, operations team that works together. And they are doing a little bit of science on this first well in terms of the way they are collecting data, and we're pleased with the timing. Obviously we wanted to move things a little faster along, but science, getting the right science on the initial wells is very important.

That's helpful. Thank you. And then in terms of reserves, could you talk about the revisions, and break that up by price and performance. And further if you could, what part of your visions of proved develop versus (inaudible)

Again, I think we're going to tack about that in detail, but -- There weren't significant revisions.

Yes, there weren't significant revisions.

Yes, but that's going to be filed in the Q. And that's next Thursday. So we have got to wait until we get that filed.

Qualitatively in terms of the revisions, what were the drivers there? Was it price related and was it just plugs getting removed or (inaudible) and crude development (inaudible) qualitatively?

Again, I guess kind of the guidance we'd 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 were also some nice extensions and revisions upwards in some other areas.

Thank you very much.

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

Morning.

Hi, Adam.

Some of my questions have been asked and some of those were actually answered.

The others we'll answer next week, right, Adam?

Exactly. In your area of the Eagle Ford, what is the expected liquids content across the play for you?

I think 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 Web County, we do believe it is going to be more of a dry gas. It is farther from the market, so in terms of adding significant production impact in to 2010, it's going to have to go a little slower, and quote, more calculated. When we get over to our -- as I move East and we get in to our THS Sun area, we have acreage that is really right on the reef on slightly up dip behind the reef. We're waiting to see some of the first wells drilled, but we anticipate that is going to be much oiler in that area.

As we move over to the AWP area, where we have excellent infrastructure and things can kind of move faster in terms of getting to 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 hype environment. So we're looking for some exciting results there. But, again, that would be dry gas as we're expecting. And we move up in to the field area proper, where the joint venture is, we see that more of a gas area with some nice condensate yields. Although, we don't expect it to condensate. We think we'll have some nice liquids in there. And there's every indication from data around us that it should be there. And in our northern AWP area, which was not included in the joint venture, we're actually seeing some oil wells or very, very oily on strike to us. So, we're thinking that is going to be liquids. And we have 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.

So, I'm trying to quantify this, but as you move towards your year end production in reserves is the mix of liquids, I guess it's going to slow less than would be implied by where you are going to drilling. Is that a sensible comment?

Yes, you would assume with the acreage activity in South Texas focused on gas, that our shift would be a little mores gassy. But obviously think high liquid content of some of this stuff just like the AFP wells, a good example, will help mitigate that. And that's one of the reasons we want to continue drilling in Lake Washington is to keep that oil production content up, I mean, for obvious reasons with the price disparity on a BTU basis between liquids and gas.

I just want to clarify, the exit rate versus the first quarter guidance on production and costs, how much of that is weather, maintenance? There 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 of that is volumetric, and how much of that is additional maintenance?

I wouldn't call it a large gap. It's a small gap. We did have some very, very cold weather. And we have 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 cold 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 or that 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'll building.

And Adam to the second part of your question relative to the per-unit cost, it's almost entirely a volumemetric thing. We meal very confident we can hit those full-year per unit metrics that we have guided.

Okay. Great. Thanks.

Thanks, Adam.

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

Hey, you guys with (inaudible) RBC here. Real quick just kind of continuing on the Eagle Ford, you have got your first two wells drilled at this point in time, that includes the horizontal portion. And just curious as to the drilling times on those wells and how long the laterals were?

Don't have exactly the drilling times, but I can give you that most of the laterals, both of the laterals were 3,800 feet. And both of these wells did have pilot holes where we drilled vertically through the base of Eagle Ford, cut coarse, land a full sweet of logs, plug back and then kicked off the lateral. 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, both of those wells, they dropped that intermediate string. And they used this open hole or rotary steel bore assembly where we drilled 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 curve would take six, seven days to build. Both of these wells I can tell you came in significantly under our original AFP.

Okay. And I guess sticking with the Eagle Ford here, just curious as to whether or not you guys have anything baked in to your production guidance in 2010 for Eagle Ford's success?

Well, we do have obviously some production baked in, built in for Eagle Ford's success and Olmos's success, but we have risked that. We believe we could have some substantial upside to the guidance we provided depending on how we provide, but because Eagle Ford is new, and really just beginning the Olmos, you want to get in to that and get some real performance before you get a little more aggressive with your guidance.

I have got to say it again, next week we're going to have our analyst day, we're going to show you a lot more detail. For those of you that are following the Eagle Ford already, and you know what is happening out there, this is probably old news, but last year at 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 have made, core data that we have 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 have drilling that is going on north of us, and we actually have drilling that's going on south of us.

Okay. I guess last question here for you guys, the wells that you plan to drill in your program here in the Eagle Ford in 2010, do you think you'll be able to get those wells on production pretty quickly after fracking them?

Well, I think all of the wells -- 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 ere Terry alluded to earlier, out in Web County, in our Las Tiendas, our Fasken area, the structure 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 the market outlets, all of the infrastructure Thursday of next week.

Okay. Thanks, guys.

Thank you, Leo.

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

Good morning, folks.

Hey, Andrew.

Hey, Andrew.

I had a couple of questions on, as you look at your activity for 2009 a little bit in 2010, look at south Texas on the reserve replacement standpoint I guessing mostly were drilled were probably puds. As you look at 2010 can you give me a rough breakdown of what you would expect to drill that would be puds very probable?

Andrew let me just clarify. Did you say you thought most of what we drilled in 2009 were puds?

For south Louisiana.

Oh, for south Louisiana.

Yes, South Texas could be mostly all probables.

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

Yes.

I guess looking forward then, it's 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. Yes, I think you can see that.

I think that's fair.

Okay. And then just had a commentary earlier, was the extension of the Olmos play with the second well that brought it to about two miles to the south and you said one file to the west; is that right?

Yes, actually probably about two files to the west as well. So two and two.

So it's looking like, I guess four sections, so maybe possibly 20 wells on 80-acre spacing? Yes, 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 spaces between the Olmos and the Eagle Fords. And we're seeing those a little differently right now, but we'll give you a lot of detail next Thursday.

Okay. Cool. And my last two questions were, one, looking at the 300-barrel a day increase that you guys got there in South Texas. How much of that came from Olmos wells, and if so, how many Olmos wells did that include?

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

Okay. And the last question was I guess thinking about, all the work you're doing in south Louisiana, how much of that is I guess how is the pressure maintenance kind of going? Are you guys still on water injection wells there? Is that something you guys are still testing? Or are you guys moving the program over to primarily just shallow drilling right now?

Well, 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 Ford area efficiently before we inject water in. Because of some of the more complex geology in that area.

Okay. Great. Thank you for your time, gentlemen.

Thanks, Andrew.

Our next question comes from the line of Derrick Woodfield with Canaccord.

Good morning, and congrats on the quarter.

Thank you.

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

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

Okay. And second on the Olmos, based on well control and the work you have done on the deposition environment, could you offer any color on the amount of exposure you might have to condensate (inaudible) in the southern part of AWP?

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

And I don't 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 where the oil, oil condensate gas, and then our gas window actually switches, so.

Okay. On the Eagle Ford could you offer any insight on maybe acreage acquisition strategies for 2010? Or your acreage strategy for 2010?

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

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

Well, I think we're spreading our bet.

Okay.

We have got what we really refer to as five different areas that we think are very well defined and each one of them has very good attributes. And we're in the process of testing those.

Okay. Thanks for your time, guys.

Thank you.

Our next question comes from the line of Derium Mabaly with Global Data.

Okay. Hello, gentlemen, good morning.

Good morning.

Okay. I have a pretty long list of questions, but I will ask you just a few that I (inaudible). Okay. Now that crude prices have increased much about their PSE levels, but that didn't happen in case (inaudible). And you guys go ahead next year, I mean, in 2010 and 2011 in the case of Eagle Ford shale, I mean, how do you see those natural gas prices affecting your strategy as to whether to go ahead with either the (inaudible) or just postponing until these prices help you to do better?

If I understand the question correctly, and just for everyone's benefit there is some breaking up on the call some, 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 strategies. Clearly, they impact them a couple of way. They impact them in terms of cash flow available. We have historical spent 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 effect the economics. We think currently the current strip today fully supports the economics in Eagle Ford and Olmos. We have also used various (indiscernible) management strategies to help mitigate and provide some floor for downward price movements. We will continue to look at and revise our price risk management strategies accordingly. In something like the Olmos and Eagle Ford development that is much more predictable, and if there is price sensitivity you may want to consider in some form locking those prices in in a little bit more positive way to help underpin your future cash flows and your economics. And we'll be looking at that.

Okay. Apart from this, I just wanted to know how would you prioritize these development programs in 2010 and 2011 simply because you have these production optimization programs coming on, and you have the Eagle Ford and you have got the south Louisiana program. So how do you prioritize these over time?

Well --

In terms of the capital budget, and all of this planning?

Well, I think clearly this year, we have to evaluate all of our position in South Texas and the Eagle Ford. This is a year of evaluation for us. So you'll see a fairly strong portion of our budget going towards South Texas this year with a lesser but still materially important part of the capital towards Southeast Louisiana, in particular Lake Washington and Bay de Chene And in Lake Washington, it will be a lot more shallow to enter immediate drilling. At Bay de Chene we do have some oil prospects that we want to drill there, that would actually be reserve adds in a number of those cases. So it's all very important to our portfolio and to our performance. So we have to issue priority to all of it to run it parallel. And we have our organization set up in such a way that we can run these things in parallel through different asset teams.

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

I'll take that. I think as I had said earlier, while we have now drilled two Eagle Ford wells and we've got one in a joint venture, we have not completed any of them. We don't have any of them on production. So what 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 in to the year, being a little on the conservative side in terms of what we think we can do in terms of production growth. And we have risk that activity. We believe that there is upside to our guidance, but we need to go out and execute and performance before we put that into the numbers.

Yes, I think I would add to that 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 we can ramp up activity without taking undue financial activities. We have monitored these markets all year Long, and if we continue to have good results, of course we'll if we continue to have good results, of course we'll be increasing activity.

Hopefully. Okay. Fair enough. Thanks for your time, gentlemen.

Thank you.

Yes.

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

Yes, hey, good morning.

Hey, Rick.

Could you talk about was the well cost on these Olmos horizontals around kind of $5.5 million? Is that in the right ballpark?

On one of them, as I mentioned the 36H we drilled a vertical, cord, the Olmos, (inaudible)sweep logs, plug backs. So that's a little bit more expensive, but, yes, I would say- 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 do want to cut core as we extend out further. On those areas where we don't do the science you are probably down in the low $5 million range on those wells that you are doing a little bit more science on in the $6 million to $6.5 million range, I would say.

Yes, 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 readying to go in to a manufacturing mode, there is a lot of cost savings you get in terms of how you actually drill your wells, and how you set IP your completion jobs.

Got it. And you had talked, I think about trying to enter cut out the immediate for an intermediate string of casing, and that might save you as much as $1 million. I guess did that work, or?

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

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 could effect the rates of return, on paybacks on the wells if you have liquids.

Significantly. And also that pertains to the Eagle Ford. Of course, it's a function of, rate and liquids content As you get in to the deeper higher pressure at Eagle Ford, those tend to produce much higher rates. So you have a number of things going on there from a time value of money and economic perspective.

Yes, and I would also like to mention that we have been in AWP for, 20 years, 20-plus years, and we understand the Olmos and the gas associated with it 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 light-in liquids that add to the profitability.

Got it. Great. Okay. Thanks very much. Great call.

Thank you Ray.

Our next question comes from the line of BQ (inaudible) with Jefferies.

Hi, good morning. Can you talk about service availability in South Texas? I recently heard of some (inaudible) there.

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

But I would add to that that we're 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 in to this area. They're following the money, so there's a good opportunity for new entrants in this area.

Okay. So if you want to schedule a frac up today, is there a wait time? Or can you get a crew fairly quickly?

Well, we actually work well in advance on our frac schedules. And we have scheduled brokered with our service providers, where we have kind of a two-way commitment of hitting a window of time around our frac schedules. So far that has been working pretty good.

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

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

Okay. Fair. Thank you.

Thanks, BG

(Operator instructions). Our next question comes from the line of Seth Menoth with Zimmer Lucas.

Hello.

Hello. Oh, okay.

Hi, hello there. Sorry about that.

That's okay.

I just had a quick question regarding the high BTU, and your midstream contracts. And how you guys are going to be booking these reserves? Are they going to be post-processing and what is the pop or PTL contract associated with the high BTU.

Well, first of all the hight BTU comment, AWP Olmos gas has always had a high BTU. It's typically been anywhere from 1,100 in parts of the field up to 1,250 to 1300 BTU gas. We dropped some of those liquids out right there in the field, so that's not a processing issue at all.

Okay.

Other parts of that BTU string we have taken historically to plants in the area. And we do get a net-back arrangement. As to how they're are booked and those kinds of things. we follow very precisely the rules of the SEC, and really, our reserve engineers, and reserve auditors have all of that detail. But it's not a material difference how that is handled. Okay.

I mean, I'm just kind of questioning, like, are you guys going to take title the NGLs?

Well, I mean in terms of titles of the NGLs, we have title in the ground. And, again, I think you have to look at every processing contract you have, because you could ride them differently. Sometimes you get a percentage of the liquids, as though you have got, quote, title. But once that gas leaves your sales point, really, you want your common carrier to have responsible for it, and effective title.

Okay. So, I mean, just like for for example on the Olmos, the one that had to condensate, it was like the gas portion, what is the BTU associated with that gas portion?

It's about 1,250.

Okay. And 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?

Go ahead.

You get what I'm trying to say?

Yes, we report the NGLs --

Okay. So you would report the NGLs.

Yes, we do. Yes. Yes.

Okay.

Yes, that's in our reports.

Okay. Thank you.

At this time there are no audio questions . All right. Well thank all of you for listening in. We appreciate it. We're certainly glad to be in 2010, and looking forward to

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