Swift Energy Co (NYSE:SFY)
Q1 2008 Earnings Call
May 8, 2008 10:00 am ET
Paul Vincent - Manager of Investor Relations
Terry Swift - Chairman, Chief Executive Officer
Alton D. Heckaman, Jr. - Executive Vice President, Chief Financial Officer
Bruce Vincent – President
Robert J. Banks – Executive Vice President, Chief Operating Officer
James M. Kitterman - Senior Vice President of Operations
Nick Pope - JP Morgan
Leo Mariani - RBC
Gary [Nushella] - Jefferies & Company, Inc.
Andrew Coleman - UBS
Brad Evans - Heartland
Jeff Robertson - Lehman Brothers, Inc
Good morning, my name is Shawana and I will be your conference operator today. At this time I would like to welcome everyone to the Swift Energy Company First Quarter Earnings conference Call. (Operator Instructions) It is now my pleasure to turn the floor over to your host Mr. Paul Vincent, Manager of Investor Relations.
I’d like to welcome everyone to Swift Energy’s First Quarter 2008 Earnings Conference Call. On today’s call, Terry Swift, Chairman and CEO will provide an overview. Alton Heckaman, EVP and CFO, will review the financial results for the first quarter and then Bruce Vincent, President, will provide an update. Terry Swift will then summarize before we open it up to questions. Also present on today’s call are Bob Banks, EVP and COO, and Mike Kitterman, Senior VP of Operations.
Before I turn it over to Terry, let me remind everyone that our presentation will contain forward-looking statements based on our current assumptions, estimates and projections about us, our industry and the current environment in which we operate. These statements involve risks and uncertainties detailed in our SEC reports 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.
Our industry continued to experience higher commodity prices in the first quarter of 2008. Swift Energy received a 51% higher aggregate price for its oil and natural gas during the first quarter of 2008, when compared to the first quarter of 2007. This has resulted in Swift Energy’s income from continuing operations increasing 88% year-over-year and cash flow before working capital changes from continuing operations rising 62% year-over-year.
While costs have increased over the past year, margins have remained strong. We believe that the upward movement in commodities has not been fully reflected in equity values in the energy sector. Certain non-OPEC producers are showing signs of peaking crude oil production. Limited spare production capacity is being demonstrated by OPEC itself and at the same time global demand for energy continues to be strong.
With these anticipated capacity and supply limitations, many industry experts are predicting even higher commodity prices. If this turns out to be the case, then the future could be even brighter for EMP companies such as Swift Energy.
At Swift Energy we have made major commitments to growing our reserves and production to increase our value and profitability while also helping to meet the increasing US need for oil and natural gas.
Swift Energy’s 2008 first quarter production increased 1% year-over-year. Production from the fourth quarter 2007 to the first quarter 2008 decreased 8%, slightly below our guidance. This decrease was driven by an 11% decrease in Lake Washington fuel. The production decrease can be attributed to a combination of natural formation declines in older, mature wells and a purposed effort on the company’s part to preserve reservoir pressure in the Newport area in anticipation of a pressure maintenance program that is now beginning as we start up our Westside facility.
We continue to drill deeper wells that have higher flowing pressure and higher associated natural gas content along with a mix of shallow and intermediate wells. The higher pressure from the deeper wells has increased operating pressure on our production facilities, which we believe has had a negative impact on our older existing wells. We are also handling higher volumes of produced water and additional artificial lift demand from the more mature areas of the fuel.
In addition to bringing in a number of recently drilled wells onto production, we believe the pressure maintenance activities planned for 2008 and the Westside facility start up will improve many of the production constraints experienced in the first quarter of 2008. We’ll talk in detail about these particular items in this conference call.
Swift Energy’s primary goals for 2008 are to continue to grow production and reserves through the Drew pit at reasonable costs.
Swift energy expects to grow production 10% to 15% organically and reserves by 5% to 9% in 2008. We’ve taken significant infrastructure an operational step to position ourselves for growth both this year and well into the future.
I’ll briefly mention some of these more significant events, which have occurred this year that should allow us to deliver on our 2008 plans:
First our Lake Washington Westside facility was recently completed and production is now flowing through these facilities from wells on the Westside of the field. This has allowed us to begin a pressure maintenance program in our Newport area and means that new wells can now be brought into our production facilities with minimal disruption to the existing system.
With eight wells awaiting completion in this area, this additional production capacity was certainly needed. At Bay de Chene we have tied in additional natural gas take away capacity. This allows us to reach markets and increase production rates of existing wells to put newly drilled wells on production and to drill some high impact development and expiration targets in the fields this year.
In Horseshoe Bayou we participate in one non-operated well with a 21% working interest, which is now producing approximately 30 million cubic feet of natural gas per day. This well clearly demonstrates the type of potential within Swift Energy Company’s data sets.
We also drilled an exploration well at Cote Blanche Island. This well was drilled to over 15,000 feet and is currently being evaluated.
These recent successes are the result of the long-term planning that Swift Energy employs to manage its business. Our regional focus and technical expertise, combined with an extensive proprietary merge seismic data set in South Louisiana has us focused on several current long-term projects.
In South Louisiana we continue to drill deeper, impactful wells and targets identified through our 3D seismic database. This included developing and planning subsoil exploratory test most likely early next year.
In South Texas we have begun a seismic acquisition strategy in conjunction with acquiring deep mineral rights over a large part of our AWP field. We believe the strategy we’ve employed successfully in South Louisiana of using seismic imaging to identify opportunities deeper than existing production can also be successful in our South Texas region.
Although industry service costs have risen over the year, Swift Energy’s first quarter margins were over $31 a barrel. We’re focused on both reducing costs wherever possible and remaining focused on keeping our margins intact.
Higher than anticipated commodity prices and margins have led to better than expected and higher estimated full year cash flows; as a result, we are raising our 2008 full year capital-spending budget to the range of $475 to $575 million from the previous range of $425 million to $475. This increase will allow us to allocate and accelerate the exploitation opportunities in our South Louisiana and South Texas data sets.
If results continue to be better than our expectations, we have the project inventory to increase our capital outlays even further later in the year.
With several major projects behind us, our operational strategy for the rest of the year can be summed up in one word, execution. We have established exceptional operating flexibility that, when combined with the most extensive opportunity set in the history of the company, will allow us to grow reserves and production in 2008 and beyond.
With that introduction, I’ll ask Alton Heckaman, our CFO to present the first quarter 2008 financial results.
Swift Energy is off to a great start in 2008. As Terry mentioned, first quarter was quite strong, as revenues were $199 million, up 53% over 1Q ’07.
Net income from continuing operations was $49.8 million, up 88% and diluted EPS from continuing operations came in at $1.61, an increase of 86% compared to first quarter 2007. While cash flow, before working capital changes increased 60% to $4.41.
Production increased 1% to $2.57 million barrels of oil equivalent. As you know, crude oil prices are very strong and with approximately 68% of Swift’s current production coming from crude oil and natural gas liquids, this current oil-pricing environment continued to have a very favorable effect on Swift’s financial results.
With Swift’s crude oil pricing averaging over $99 per barrel over the first quarter, our domestic average realized blended price for BOE increased 51% to almost $78, as compared to approximately $58 for BOE during the first quarter a year ago, allowing Swift to increase its quarterly oil and gas revenues 54% over the first quarter of 2007.
As Terry mentioned in his intro, it’s obviously all about the margins.
Sector and price sensitive costs are on the rise, but Swift continues to focus on our controllable pre unit costs and metrics.
As to the first quarter of 2008, G&A came in at $3.86 per barrel, in line with guidance; DD&A per unit came in at $20.43, also in line with guidance. Production costs came in above guidance at $10.28 per barrel, primarily due to certain work over activity in 1Q ’08, which Bruce will discuss further in the operations update.
While production taxes increased in tandem with higher prices, but actually decreased as a percentage of oil and gas revenues due to the change in Swifts production mix and location and interest expense came in at $3.38, the result of higher line of credit borrowings during the first quarter, mainly due to the delayed New Zealand asset sale closing.
We therefore realized income from continuing operations for the quarter of $49.8 million, $1.64 basic and $1.61 diluted, again, up 88% over1Q ’07.
As mentioned in today’s press release, we’ve agreed to sell the remaining portion of our New Zealand assets for $15 million, resulting in a $12.8 million gain upon closing, expected to happen in the second quarter of’08. We also will close on the sale of the other larger portion of our New Zealand assets before mid-year. All in, we expect to realize total cash of between $95 and $100 million from this disposition, but will reduce our bank line.
Cash flow before working capital changes for 1Q ’08 came in at $136 million or $4.41 per diluted share, while EBITDA was $140 million for the quarter, or $4.54 per diluted share.
CapEx for the first quarter of 2008 of $176 million allowed us to delay the closing date on the sale of the New Zealand assets, resulted in borrowings under our line of credit of $223 million at the end of the first quarter. Even with this level of borrowing we still have plenty of liquidity and resources available for any additional value add in strategic opportunities.
With respect to Swift’s hedging activity, we’ve purchased natural gas floors for approximately 45% to 50% of our production for 2Q ’08 and 30% to 35% of 3Q ’08 production. With respect to crude oil floors, we’ve purchased approximately 40% to 45% protection on our third quarter 2008 production. Please see our website for complete and current detailed hedging information.
We’ve also included additional financial and operational information in our press release, including guidance for the second quarter and full year 2008.
This quarter was another great financial quarter for Swift Energy Company and the momentum continues to build.
With more on that, I’ll turn it over to Bruce Vincent for an overview of our operations.
Today, I will discuss first quarter 2008 activity, including our production volumes, our recent drilling successes, activity in our core operating areas and our plans for the rest of 2008. First, let me talk about production.
Swift Energy’s production from continuing operations during the first quarter of 2008 totaled 2.57 million barrels of oil equivalent, or 15.4 billion cubic feet equipment. That was an increase of 1% from the 2.53 million barrels of oil equivalent produced in the same quarter of 2007.
As guided, during our last quarterly conference call, sequential production decreased 8% when comparing the first quarter 2008 to production in the fourth quarter of 2007.
Now for our drilling results:
Swift Energy completed 35 of 36 wells in the first quarter of 2008. The company completed 34 of 35 development wells, for a success rate of 97% for the first quarter of 2007. We also drilled one exploration well at Cote Blanche Island.
I will begin, briefly, to review our activity in each of our core operating areas, beginning with the Lake Washington core area. The Lake Washington core area includes both the Lake Washington fields and our Bay de Chene field.
Production during the first quarter of 2008 averaged approximately 16,105 net barrels of oil equivalent or 97 million cubic feet of equivalent per day in this area. This was a decrease of 12% when compared with the fourth quarter of 2007 average net production from the same area.
Lake Washington averaged approximately 14,312 net barrels of oil equivalent per day or 86 million in cubic feet equivalent per day.
At the Lake Washington field in Plaquemines Parish, Louisiana, activity levels have been high. The Westside facility has been fully commissioned and oil is now being processed by this facility. We will be working diligently over the next month or so to optimize production in the field, utilizing all four production facilities and looking at the numerous shut in wells to determine which ones can be brought back on production quickly.
It was noted in our press release that one of the primary reasons our lease operating expenses were higher than forecasted was due to increased workover expenses. Well, sometimes that’s exactly what you want. As an example, in Lake Washington we performed ten coil tubing acid stimulation jobs this year, which resulted in an increase in production test rates of approximately 145% after the workover on these wells were performed. Obviously with the Westside facilities coming and the price of oil, workovers like these make a lot of sense.
We expect to continue this program during 2008 and now with the new facilities now in place, we should see the benefits of these higher rates.
We’ve also begun injecting water into two reservoirs in our Newport area as part of a pressure maintenance project, but it should be noted that it will take several months before we see a production response from this initiative. Water injection has just begun and we are not yet injecting at our desired rates into these reservoirs.
Swift Energy drilled three successful development wells in the first quarter and since the beginning of 2008 we’ve actually finished drilling nine wells in Lake Washington. The wells have ranged in depth from 5,672 feet to as deep as 17,005 feet and they’ve encountered true vertical net pay ranging from 54 feet to as high as 423 feet. One of these wells has been completed, but the remaining wells have not and will be completed and brought on production over the next several weeks.
It should also be noted that the well with the 423 feet of true vertical depth net pay was in fact the second best well Swift has drilled in Lake Washington.
Additionally, while we don’t expect to achieve 100% success with our drilling activity all the time, our recent successes, as evidenced in 2008, are indicative of the value of the 3D data set that we put together.
In Bay de Chene the previously announced increase in export capacity has been recently completed, positioning the company to increase production in this area during the remainder of 2008.
The BDC UB #150 well, which was drilled at 9,600 feet, encountered 60 feet of true vertical net pay, and is scheduled to be completed and placed on production by the end of this month; we’re also planning additional wells in Bay de Chene.
We currently have five barge rigs contracted in this area: four are operating in Lake Washington and one in Bay de Chene. One of the rigs currently in Lake Washington will be released for repairs in the second quarter, although we expect it to come back after that, while two rigs are expected to be added at Lake Washington during the third quarter.
We expect to drill 20 to 25 additional wells in Lake Washington this year and three to five more wells in Bay de Chene.
In our South Texas operating region, which includes our Cotulla area and our AWP field, first quarter 2008 production averaged 7, 312 barrels of oil equivalent per day.
In the first quarter we successfully completed 11 development wells in the AWP area and 13 development wells in the Cotulla area. Additionally, the company recently acquired deep drilling rights in the AWP field over approximately 11,000 acres, below the Olmos sands and we do plan to drill an Edwards test later this year.
We plan to have two rigs in AWP during the second and third quarter to continue our drilling program there. We will drill 15 to 20 more wells this year in this area. We have one rig in Cotulla and we will drill 15 to 25 more wells in this area during the year.
In our Lafayette North operating region, which we’ve previously referred to as Toledo Bend, this area contributed 2,490 barrels of oil equivalent per day of production for the first quarter of 2008. Included in this area are our Brooklyn and Masters Creek fields as well as South Bearhead Creek. In our Masters Creek field in Vernon and Rapides Parishes, we were unsuccessful on one well, which was plugged and abandoned after encountering mechanical difficulties, prior to reaching it objective horizon. We are reviewing the issues related to this mechanical failure and hope to reschedule this well later in the year or early 2009.
At South Bearhead Creek in Beauregard Parish, Louisiana, Swift Energy drilled four development wells during the second quarter of 2008. One of these wells is currently on production with the other three wells waiting on fracture stimulation to begin production. Additionally, two wells drilled in the fourth quarter of 2007 were brought on production during the first quarter. We expect to drill at least two to three additional wells in this area in 2008.
South Bearhead Creek continues to perform well and we will continue to enhance the production profile of this field.
In our Lafayette South operating region, which is comprised of Horseshoe Bayou, Bayou Sally, Jeanerette, Cote Blanche Island and Bayou [Bijon], production averaged approximately 1,760 barrels of oil equivalent per day during he first quarter.
In Jeanerette, the Aldine Sugar factory #21 was drilled during the first quarter of 2008 and is currently awaiting completion. Our work in this field has been encouraging and we plan on increasing production and reserves here in the future.
Swift Energy participated in one non-operated development well drilled in the Horseshoe Bayou Field during the first quarter. The well-encountered 155 feet of true vertical net pay and is currently producing approximately 30 million cubic feet of gas per day with flow and tubing pressure above 10,000 psi.
Swift has a 21% working interest in this field and we are pleased with the results of the well, as well as the potential that we see for the area. We will begin drilling another well in the Horseshoe Bayou, Bayou Sally area during the second quarter, with Swift having an approximately 65% working interest.
In the Cote Blanche Island area an exploration well was drilled to a little over 15,000 feet. This well is currently being evaluated. Our plans for the remainder of 2008 call for Swift energy to drill up to three to five additional wells in this region. Swift Energy currently has one land rig contracted for the area.
Thanks for your attention and I’m going to turn it back to Terry to recap it.
Before we open the line for questions, we want to reiterate Swift Energy’s 2008 operational plans and goals.
We are focused on reserves and production growth. Drilling results so far this year in Lake Washington, Bay de Chene, and South Texas, provide us with confidence that we will grow reserves 5% to 9% and production 10% to 15%. We are also focuses on protecting our margin by managing our drilling and operating costs.
To review some of the highlights from this morning, first I’d like to mention that Swift Energy Company had strong financial results in the first quarter and we intend to continue delivering on our operational plan in 2008.
In the first quarter of 2008 our revenues increased 53% to $199 million. Income from continuing operations was $49.8 million, or $1.61 per diluted share and cash flow before working capital changes was $136.3 million, or $4.41 per diluted share. While these results all lead directly to added value and further solidify our strong balance sheet, we believe they will also improve with continued performance of our assets.
In the first quarter of 2008 we had production of 2.57 million barrels of oil equivalent for the quarter, a 1% increase over the first quarter of 2007. We have numerous wells ready to be completed and come on production in the next several weeks, including eight wells in the Lake Washington area, one well in Bay de Chene, one in Jeanerette, and three in South Bearhead creek.
While continuing to drill deeper, high impact prospects, Swift Energy has developed a large inventory of lower risk development opportunities. Additionally, production capacity restraints being removed from Lake Washington and Bay de Chene should set the stage for production growth in the second half of 2008.
Finally, our conservative management and financial philosophy’s have positioned us to continue our dual approach of growing through drilling and acquisitions.
At this time we’d like to begin the question-and-answer portion of our presentation.
(Operator Instructions) Your first question comes from Nick Pope with JP Morgan.
Nick Pope - JP Morgan
I was wondering if you all would be able to split out the production decline you all talked about from Lake Washington, you said it was from the natural declines and like it intended reduced production due to pressure maintenance? Are you able to split that number out, how much is due to the pressure maintenance?
We’ll try to give you a good flavor for how to break that out, but we really don’t have a split of the various items. Let me first categorize them. First of all, in Lake Washington you do have natural declines that are going on in the wells that just goes along with every field.
When we specifically refer to the natural declines there, we’re trying to isolate those natural declines, which we believe across the whole field are roughly in the range of 20% as opposed to part of a decline that you generally see is also due to older wells not being able to get into the system, higher pressure wells pushing them out.
In terms of splitting it out, how much of that 11% in Lake Washington is older well decline, my gut feel would be somewhere between 1/3 to ½ of it. How much of that decline was the result of facility’s issues, we’re trying to piece that apart. My gut feel there would be that, that might be 1/3 of it, something like that.
I also should note that we’ve just come out of the winter season and we always experience a decline in these facilities out there because of colder temperatures it impacts our separating abilities out there, it impacts how the fluids flow through the lines especially. That also is part of the decline that we always experience in that part of the year; that could have been as much as 20% of the decline that we experienced, it’s hard to say.
As to the pressure maintenance, we purposed to actually choke back some of the wells in the Lake Washington area around Newport, because they were having higher quantities of gas and the gas takes up a lot of space in the flow lines, it also creates a problem in terms of export capacity relative to oil going through the facility’s. You really don’t want that much gas when you’re actually beginning pressure maintenance programs, you like that gas to be settled down.
We’re trying to get the pressures up in Lake Washington. We clearly had to have the Westside facility in place before we could begin the injection into these primary zones. Right now we only have two of the zones that we’re injecting in.
Again, a gut feel might be 20% to 30% of that decline might have been attributable to us pinching back on some of that production. It’s real hard to piecemeal it out. I hope I’ve given you some idea of it though.
Nick Pope - JP Morgan
One other question I had was what are you all seeing in terms of drilling costs, service costs trends right now. I know you’re all bringing on a bunch of rigs. How do things look there?
We recognize that in some places the rig count is increasing. Fortunately in the areas of our operations, we’ve not seen that and so we’ve not seen an increase in drilling rig rates. Nor have we seen a limitation of availability. We’ve been concerned about that, we’ve talked about that for some time, because we recognize with the $11 gas, $100 whatever oil, people’s budgets are bigger and people will step up the activity, it improves the economics and lots of things and we’re guarded about that as well because we want to be sure we have access to equipment to get our projects done.
Within our areas we’ve not seen that. We continue to see availability and feel like we’re going to be able to execute our plan, certainly with regard to drilling rig availability.
On the service side, generally on the service side we haven’t seen a significant change either. I think the one place you’ve seen some is in steel. One of the things that we’ve actually gone out and done is preplaced a significant order for tubular, both recognizing the costs of potential increase, but also availability. I mean we expect the tubular market to tighten up and we’ve tried to go out and secure a fairly significant order to plan ahead for our activity.
Your next question comes from Leo Mariani with RBC.
Leo Mariani - RBC
I’m curious to find out a little more about this Edwards test that you’re talking about beneath AWP. Is that the limestone down there you guys are targeting? I’m just trying to get a sense of how you’re going to drill, are you going to drill a vertical or horizontal well, are you just take a crack at that and any artificial information you have, that would be helpful.
Yes, we’re real excited about the Edwards trend. As you’re well aware that trend is a very extensive trend, it goes basically from the Rio Grande all the way over into the AWP area and then even further North East of there. In our particular area, in our areas of operation, we had that Edwards trend identified both in the AWP area and the TSH Sun area, some of the Cotulla properties.
We have done extensive review of our seismic inventory. We’ve acquired some 3D seismic in the areas and we are also in the process of shooting some new proprietary 3D data that will merge in with what we already have.
We’ve got extensive well control in AWP itself, there were some earlier penetrations that go back, I believe into the 80’s, that actually did test some Edwards production and in that area it gives us a pretty good calibration point. We don’t have all of the rights as of yet. There are other folks in the area that are exploiting the Edwards and as we understand, there is some other drilling going on in that area.
There’s a well that we might have a partial interest in this year, but we also are planning some of our own wells on our own acreage, our own 3D data set.
Some of the highs that you see in the Edwards, in the old days they really just drilled a high part of the reef, we’re seeing indications in 3D that you’ve got some patchwork veracity indications in the stratigraphy out there where you can drill actually off of the primary high and we believe you can make some really nice wells. We’re talking about horizontal wells; we’re talking about wells that will be approximately at about 12,000 feet.
Should these early wells, both the ones that we participate in on a partial interest as well as the ones we’re looking at, at 100% work this year that would be a lot of extensive Edwards’s opportunities in the years to come.
Leo Mariani - RBC
Could you guy’s maybe kind of help to quantify what you think the sort of incremental workover expense was in the first quarter that kind of drove up your LOE a little bit here?
We incurred and you’ll see a break out in our cube, but we incurred probably about $3 million in expense workovers in the first quarter of ’08. We had budgeted for and guided for about $0.5 million, so the dealt on that’s about $2.5 million. Clearly you can see how that had an impact on our per unit LOE, about $1.00 per unit and about $0.05 on an EPS effect, so that’s the effect in the first quarter, but as we discussed these workovers are going to have some production into the future. Clearly at these pricing levels they were worth the expenditure.
Leo Mariani - RBC
That’s kind of on the same range of my next question. Can you guys just maybe talk about the results you saw in terms of additional production from those ten workovers?
We can. I don’t have the specific details in front of me, but I think as I mentioned during the call itself, the ten collective coil tubing acid stimulation jobs that we performed in Lake Washington did actually result in an increase of actual production test rates, approximately 145% above the test rates of those same wells prior to the workovers.
Leo Mariani - RBC
So, basically you’re comparing the IPs after the workovers here to kind of the original IPs of the wells?
Yes, so if you had a $100 barrel a day well, just as an example, after the workover was performed, the new test rate of that well would have been 145% above that. That’s the kind of thing we’re seeing across the board and that’s why we stepped up the activity. We saw the Westside facility project being on time, I think we’ve got it all along that that’d be ready by the first half.
We saw obviously the price of oil, our ability to increase our budget and so it made a lot of sense to do that. You’re basically spending capital dollars to increase production volumes, but because it’s LOE it gets expensed.
I want to add to that that we didn’t do a good job of guiding there on the workover side of the LOE piece and in this mornings call we really need to help get a better understanding of that for the folks.
We have looked at the price of oil right now and it is obviously an exceptional pricing environment we’re getting and the folks, our production operations guys have done an excellent job at looking at the fields such as the Brooklyn field and other fields where we can take wells that were, lets just say about 25 barrel a day wells, we can them up to you know, 50 barrel, 60 barrel a day wells. That doesn’t have a giant impact, but there are a lot of these kinds of things to do.
We have given direction to spend another $2 to $3 million, maybe as much as $4 million, if they can find those types of things. Doing these workovers, that’s going to come through LOE, but it will have important production gains attributable to those costs. They’re not capitalized. They generally come through LOE. We want to do them, they’ll show up during the second of the year and we’ve actually allocated the money to do that, but with output, we haven’t put the production expectation in front of you at this time and it wouldn’t impact the whole year that much, it would be something that would be more of a momentum thing going into 2008, 2009.
I don’t think that that would affect reserves; it would affect the speed at which you get it out of the ground.
Leo Mariani - RBC
Would you expect some reserve increase associated with those as well?
Yes, at this time we’re not anticipating that. We’re obviously have the reservoir engineers look at those results and if there is a basis for a little bit of a reserve uptick there, they’ll certainly look for it.
Your next question comes from Gary [Nushella] with Jefferies & Company, Inc.
Gary [Nushella] - Jefferies & Company, Inc.
You said Lake Washington in the first quarter averaged a little over $4,000 barrels a day, is it still averaging he same level right now?
Well their getting the actual numbers, I think it’s important to that we are seeing improvement in the production in Lake Washington and I’ll take this opportunity to note that even though we did have the sequential decrease, a good part of that decrease in our minds was because our newer wells weren’t able to get into facilities and as we were drilling out there, we recognized that some of these wells wouldn’t really get into the production mix and increased production.
I noted that we have eight wells in Lake Washington awaiting completion. Bruce noted in the more detailed presentation that there’s been some significant pay drilled and brought into the producing category status, once these completions come into fruition.
I’m going to step out there and I know that folks need information, we don’t have these wells producing right now, but we think we’re looking at 3,000 to 4,000 barrels of production incrementally that could come from these eight wells as well as a couple of the wells that we’re drilling right now.
I think we, I don’t have the exact net number in front of me, but I know the rates at Lake Washington are higher than that right now. Well we did just put on the Westside facility and you know, I think as I’d mentioned in the conference call in February, it’s not like turning the switch and the car starts and you can take off at full speed right away.
It will take a period of 30 to 60 days for us to properly optimize the various facilities and figure out what wells go where and what, but with the start-up of the Westside facility and the converting the Westside production mainly around Newport over to the Westside facility, we did see a significant pressure drop across the field and we did see an initial response to increased production in the other facilities.
Then gross production today is roughly 16,000 barrels of oil and another 12 million cubic feet of gas, so roughly on an equivalent basis, about 18,000 gross barrels of production a day, which is above that first quarter average.
Gary [Nushella] - Jefferies & Company, Inc.
My second question is, can you give me some idea, or maybe some range of where you think Lake Washington production might exit the year?
We could give you that. It really is kind of embedded in the guidance that we provided, but we don’t actually give the guidance in terms of a per core area.
I think it’s very important to note that the first thing that we’re doing in Lake Washington is we’re overcoming the production constraints in the field and to the extent that we had that sequential decline in the field, we believe that we’ve arrested that, we’re already showing some increase.
When you look at the overall production guidance for the year, we’re talking 10% to 15% production guidance for the year. Without having the numbers right in front of me, Lake Washington itself, from the entry point of the year to the exit point of the year ought to be well above that guidance.
Your next question comes from Andrew Coleman with UBS
Andrew Coleman - UBS
Looking at the Newport, how many injectors do you have there, is it still one and do you have plans to drill some more injectors as you ramp-up that water plain?
We do just have one injector well right now. In the first quarter we drilled two water source wells, which took up some of our activity and we do plan to drill some additional injector wells in the area, I think at least two more.
Andrew Coleman - UBS
What remains there in terms of the start up stuff, can you walk me through just how we’ll get from where we are today to full production activity? It looked like going through the rest of your guidance you’d probably get a pretty good production increase to just kind of hit that mid point at the end of the year.
Well it’s a very complex system and there’s quite a lot involved in both the commissioning process and getting everything started up, a lot of equipment and it’s a very complex field. Now you have four production facilities instead of three, each one has different attributes, so to speak. The pressure changes depend upon which wells you put in which production facility and so what we’ve done initially is we’ve taken the Newport production area, which is over in the Westside.
We’ve talked before how that’s three miles away from the 212 platform and diverted it to the Westside facility and the Westside facility now is roughly 5,000, 6,000 barrels a day approximately.
So, now what we have to do is go back into the 212 and the 6,700 and the CN3 and the 100 plus wells that are going into those various production facilities and optimize or rebalance both the pressures and the rates and the oil production; the water volumes that are coming from there, the gas production that’s coming out of there, the gas lift system, and minimize the flaring while you’re doing all that and then also look at the many, many shut in wells we have, determine which ones can be brought on quickly, obviously you want to bring them on quickly.
Obviously you want to bring them on quickly, but others have to have some various operations done to them to get them on stream, many of them have been shut in for some time. Obviously, we want to prioritize both the ones that will have the greatest impact, the ones that can be turned on the quickest.
There’s just a lot of complexity and a lot of little things that have to be done by numerous people to make all this come together. We estimate that’s going to take the next 30 to 60 days to do.
When you combine that with all of these wells that we have finished drilling, we’ve got eight in Lake Washington alone that will be completed over the next several weeks, that will range in probably potential volumes from 100 barrels to 1,000 barrels per day. Bringing those on, making sure they’re directed to the right platform and then what kind of impact that has with regard to the overall pressures.
When you bring a new high pressure well on production, for instance, that’s going to have an effect on the overall pressure of the system and so we need to find the right optimization of all the wells in all the facilities to achieve maximum rates of production.
I’d like to add to that that it’s kind of a good thing and a not so good thing. When you have this complexity, if you just had one big well behind all of that system, then you could go to one valve or you could study one set of fluid lift dynamics and be done with it, but you wouldn’t be very diversified.
What we really have is hundreds of wells and literally many hundreds of formations because most of these wells have lots of behind pipe opportunities, so the total set of opportunities to optimize really is in the hundreds, not in the tens or twenties. That means it’s very diversified and the only thing they all have in common is the facilities.
When you see these kinds of declines that we’ve experienced, the only thing in common to all these reservoirs and all these wells is the facilities. We’ve taken care of the largest part of the facility problem by bringing in Westside. We’re very pleased with the way Westsides operating, so I think we’ve now got the bull by the horns and it’s all just hard work.
Andrew Coleman - UBS
Is it fair to think about this as, with the extra facilities you’re going to add sort of a gas pipeline program and kind of keep your gas rates at a manageable level to keep as many of your lower pressure and higher pressure wells flowing?
Not sure, could you repeat that Andrew, you’re breaking up.
Andrew Coleman - UBS
I was just curious, it sounds like perhaps there was like a gas pipeline program that’s just kind of in place or is about to start up or you’re going to be looking at the gas rates across your multiple wells and kind of optimize which ones bring in the lowest marginal GOR to keep your maximum oil rate flowing through the system?
Just to clarify, we don’t have any gas cycling projects out in Lake Washington, but when we refer to pressure maintenance, we’re actually injecting water down to maintain pressure, but we do have gas cycling in the production system by virtue of the gas lift issues and there is where you do have GOR issues. By changing out the amount of gas that’s allocated to a particular well, to lift that fluid, you can optimize one well against another well. We certainly have lot of that to do in the field.
Andrew Coleman - UBS
When I look at your deferred tax rates for the second half of the year, it’s going to fall down into the 80% range. Is that because of the size in making more facilities expense as being incurred or is there probably some upside in that number?
I think we’ve guided to the conservative side and so I don’t know what side would be deferring more of the taxes, I guess you’re asking, but obviously with our current outlook it looks like we’ll be in a tax paying position this year and so that deferred portion is going to be going down.
Yes what I would tell you is that has a lot to do with $120 oil and that will increase profitability of the company. As you make a lot more money you use up some of those credits that enable you to convert taxes and so you’re going to be a larger cash taxpayer.
Andrew Coleman - UBS
On South Texas, it looks like you guys drilled kind of about 60 wells total across those two assets for the year, after about 24 in the first quarter. Is there a chance to maybe get some additional wells put in there or are there some constraints in terms of pipeline capacity or getting rigs in the back half of the year?
I don’t think, I’m not aware of any constraints in terms of pipeline capacity or field infrastructure. Right now we don’t see any rig availability or fracture stimulation services etc… and we have actually added to the budget in both those areas already and obviously if the trends continue, it would not surprise me to have us increase our capital expenditures further and that’s certainly one area that we’d be doing it in.
$11 gas are kind of no brainer economics, you know it’s great infrastructure, long life, just wonderful properties to continue doing that and while we haven’t, I wouldn’t say we’re committing to that, I think as you followed us in the past, we’re big believers in trying to spend cash flow but we want to ease into it and spend realized cash flow, not some forecasted number.
Your last question comes from Brad Evans with Heartland.
Brad Evans - Heartland
Could you remind us as to how many wells are shut in at Lake Washington at this point?
Lake Washington, when we first obtained the field, did have some shut in wells that were also in what we call a T&A category. We first acquired the field back at a time when oil prices were lower, so some of those wells were targeted on an ongoing flood and abandonment program for the lower, shallow type zones.
In total, there are over 100 wells out there that fit both the category of T&A and shut in. But, when you get to the issue of shut in wells that we know have opportunity for us, I believe that number is about 50 to 60 wells and when Bruce refers to bringing those wells back on, we’re really talking about a sample of 50 to 60 wells.
Brad Evans - Heartland
The Westside, the infrastructure that is now in place at Lake Washington supports a productive capacity of how much in terms of barrels per day?
The current infrastructure is capable of processing 10,000 barrels of oil and 20 million cubic feet of gas and another 10,000 barrels a day of water just the Westside.
Brad Evans - Heartland
So the four platforms of the four facilities in total support what type of productive capacity?
35,000 barrels a day probably.
Then the Westside facility has got an additional footprint that we put out there so that we can expand it and double what’s out there right now.
In other words add another 10,000 a day of barrels of capacity.
Brad Evans - Heartland
When will you have to make a decision as to whether you need to put that additional capacity in place?
Well we’re actually looking at that now because it’s not a large capital number, it’s probably less than $10 million in terms of capital, but it’s probably about a year lead time to design and order and get the equipment delivered.
Brad, I think it’s fair to say, we’ve made the decision that we will expand it. The decision is when we’re actually going to pull the trigger and start that.
Brad Evans - Heartland
It sounds like if production is currently around 18,000 barrels a day gross, at Lake Washington, I realize that is a gross number, but I guess I’m just looking at your guidance for liquids production for the second quarter and it looks like, I realize where it may ace right now. But, it looks like that number may be, you’ve built in some conservatives in there, is hat a fair statement?
We would hope to, yes. We’ve got to be sure that we hit our numbers.
And to be frank, yes there are some conservatives, but there’s also some unknown in the sense that with the new facility on and the other three facilities understanding exactly what we can do in terms of optimizing the production and that. We’ve got a bunch of wells that are coming on production, obviously the timing of that, making sure the completions get done successfully and so timing is probably a part of that issue, as much as anything else.
Brad Evans - Heartland
That makes a lot of sense. I didn’t catch, when there was a discussion about the Edwards formations at AWP, can you disclose or talk about how much of what your acreage exposure there is in terms of what might be perspective for the Edwards?
I’d probably hesitate to actually quantify what’s perspective.
Well I’ll take a short stab at it. In the northern part of AWP, we have two partial, two different types of parcels of acreage, we’ve got one area where we have about a 20% or so interest in the acreage and then we’ve got another area in the north where we’ve got 100% and in the Northern part of AWP we’re probably looking at a couple of thousand acres total and it’s probably roughly split between those two different types.
Let’s just say in what we might call perspective
Edwards in the Northern portion there’s maybe 1000 acres or so where we’ve got the lower interest and 10000 acres or so where we’ve to the higher interest. It’s going to take some drilling. We’re talking about perspective Edwards; we’re not talking about anything proven at this time.
As you get further to the south and you get off the main structure, the Edwards is going to be there and there is going to be some slag there and other types of things and we don’t have the specifics of prospect acreage, but we’ve got a large area down there to work; several thousands of acres where we have 100%.
Brad Evans - Heartland
Outlook with Carrie I guess, can you just talk about what the pending transaction in New Zealand plus even with your higher capital budget, with commodity prices the way they are, it looks like you’ll still, whether you’ll revise that upwards or not, but do you still have the prospect of generating a lot of excess cash flow. Can you just talk about where you hoped to see the bank line over the next couple quarters in terms of again, taking into consideration the acid sales?
I’ll take a shot at it and then I’ll let the CFO, we’ll make sure that he gets a chance to talk about that since that’s one of his areas of responsibility, but clearly we’re going to have cash flow well above what our budgeted cash flow assumed. We had used the price deck of about $75 for oil and $7.25 for the gas. Even with those prices we had built in a discretionary wedge of, we do try to be conservative in how we plan.
It’s very clear to us that that discretionary wedge will now not only be fully available, but we are believing that we could see well over $100 million and we’re taking the various steps to look at how to deploy that. Even given that, you’ve got momentum issues and timing issues, you’ve got the cash coming back from New Zealand.
I think the bank line is, as you see it, short of an acquisition that would be strategic, which we don’t have one identified right now, but short of an acquisition the bank line ought to be going down very, very considerably over the next several quarters.
You’re right on Terry. I mean basically as you know we went into the line consciously in the first quarter of ’07 to fund the Cotulla acquisition, kind of a pre-spending of the New Zealand proceeds we expected and as we’ve indicated we’re going to get some where around $100 million when all the smoke clears from our New Zealand disposition, so that will go toward paying down the line, as we said, was about $220 million at the end of the first quarter, so the cash we’ll be able to get will go towards that and even in a conservative pricing outlook for 2008, we would be paying off pretty much that line in entirety by the end of the year.
With these higher commodity prices, we’re going to have some free cash flow; we’re high grading our projects, looking at prioritizing them and then ascertaining what the best avenue is for spending those dollars.
Ill shoot from the hip, I get in trouble for doing that, but I’ll do it anyway.
Just in terms of the current strip that we’re seeing in oil prices, which we don’t want to take that money and spend it before we have it. We know how volatile this oil and gas market can be so we want the money in the bank, but we’re really seeing cash flow above budget expectations in the $30 million per quarter clip, $35 million per quarter clip. So, as that kind of comes into the bank, obviously we’ll use it immediately to reduce bank line, but as Alton says, more projects and we’ve tot things we could put the money to good use to.
I think we’ve used the hour wisely, we appreciate everyone joining us for our conference call and we look forward to speaking with you again next quarter.
This does conclude today’s Swift Energy Conference Call.
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