Venoco, Inc. Q1 2008 Earnings Call Transcript

May.12.08 | About: Venoco, Inc. (VQ)

Venoco, Inc. (NYSE:VQ)

Q1 2008 Earnings Call Transcript

May 12, 2008 11:00 am ET

Executives

Mike Edwards – VP, IR

Tim Marquez – Chairman and CEO

Mark DePuy – COO

Tim Ficker – CFO

Analysts

Mike Scialla – Thomas Weisel Partners

Joe Allman – JPMorgan

Jeff Robertson – Lehman Brothers

Steve Berman – Pritchard Capital Partners

Biju Perincheril – Jefferies & Co.

Operator

Good day ladies and gentlemen and welcome to the first quarter 2008 Venoco earnings conference call. My name is Tanya and I'll be your coordinator for today. At this time all participants are in a listen-only mode. We will facilitate a question and answer session towards the end of this conference. (Operator instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the call over to your host for today's call, Mr. Mike Edwards, Vice President, please proceed sir.

Mike Edwards

Good morning everyone. Venoco issued a press release today on our first quarter 2008 results. We also filed our 2008 Form 10-Q with the SEC. On the call today to discuss the first quarter results we have Venoco's Chairman and CEO, Tim Marquez; CFO, Tim Ficker; COO, Mark DePuy; and other members of the Venoco management team.

Before we get underway, let me make a couple of comments regarding forward-looking statements. All the statements made in this conference call, other than statements of historical fact, are forward-looking statements within the meaning of section 27A of the Securities Exchange Act of 1933 and Section 27E of the Securities Exchange Act of 1934. These statements are subject to a wide range of business risks and uncertainties.

Any number of factors could cause actual results to differ materially from those presented in the forward-looking statements, including, but not limited to the timing and extent of changes in oil and gas prices; the timing and results of drilling activity; the possibility of delays in completing production; treatment and transportation facilities; difficulty obtaining third party services, including transportation and higher than expected production costs; and other expenses.

The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of unproved or 2P reserves, which may be potentially recoverable through additional drilling or recovery techniques, are by their nature more uncertain than estimates of proved reserves and accordingly are subject to substantial greater risk of not actually being realized by the company.

Forward-looking statements made about the Hastings complex and the option contract with Denbury Resources, are subject to business risks and uncertainties not in Venoco's cost control including but not limited to the exercise of the option purchase, the implementation of the CO2 flood and the production results and reserves if the flood is implemented. Information regarding results from hydraulic fracturing program in the Sacramento basin is based on the results to date, which are preliminary and future results may differ.

All forward-looking-statements are made only of the date hereof and the company undertakes no obligation to update any such statements. Further information on the risks and uncertainties relating to forward-looking statements are set forth in our filings with the Securities and Exchange Commission. The earnings release and the relevant non-GAAP reconciliations are available on the investor relations page of the Venoco website, which is www.venocoinc.com.

Now I would like to introduce Venoco's Chairman and CEO, Tim Marquez.

Tim Marquez

Thanks Mick you really nailed that one there. Welcome everybody who's called and our listening to our webcast. I am very please today to review our first quarter results; we'll just dive right in. Starting with production, our average daily production volume for the first quarter was 21,026 barrels oil equivalent per day that's an increase of about 5% over fourth quarter production of 21,100 BOE per day. Including the first quarter production as a onetime true up of a legal title matter related to Sacramento Basin interest and royalty allocation to West Montalvo field.

Gas of wells in cubic feet produced during the quarter were 21,760 BOE per day, which is a 3.3% increase over the fourth quarter. Productions is up 19% year-over-year from first quarter 2007. We saw the largest increase in Sacramento Basin, a slight increase in Texas and a small decline in Southern California, due mostly to downtime related to offshore wells. We were able to get the growth back in the line before the end of the first quarter.

Worked very hard to update our presentation for the IPAA conference in early April, our goal is to provide more information about our individual regions related to production, potential reserves in the economics of various projects. You can access it on our website. In our presentation we confirm guidance and do so again today. Our guidance for 2008 production is 20,500 to 21,500 BOE per day. As I said on the year-end call in March, we believe we have been conservative in setting this production guidance and are very focused on beating and beating it.

During the second quarter we expect to have our annual maintenance shutdowns for a large offshore assets principle with platforms Holly and Gill. We therefore anticipate some effect on average productions during the quarter and anticipate the second quarter production to be similar to the first quarter. For the first quarter, capital expenditures were about $63.7 million with approximately 54% expense in the Sacramento Basin, 22% expense in California and 20% in Texas.

For the full-year, our forecast for capital expenditures for exploration and development remains at $235 million, which you expect to be within operating cash flow before working capital adjustments. If you look at slide 27 of our IPAA presentation. You will see our forecast for adjusted EBITDA under various pricing scenarios. Before oil and gas price remain at high levels we may make a modest increase to our CapEx budget later on the year.

We continue to actively pursue acquisitions where we don't forecast expenditures for acquisitions. For the operating expenses and G&A, first quarter lease operating expenses were $14.68 per BOE, which is a decrease of 20% from the fourth quarter of 2007 of $1834 per BOE. We attribute the reduction to a completion of remedial activities in the Hastings Complex as well as the production volume increase in Hastings in the Sac Basin.

The full year 2008 we continue to expect to see lease operating expenses of $15.05 dollars per BOE. First quarter G&A expenses were 474 per BOE that excluding FAS 123R charges. G&A expenses were 4.09 per BOE. So with that I would like turns over to Mark DePuy discuss to store performance.

Mark DePuy

Thanks Tim, I'll started with the Southern California operations. In the South Ellwood, the State Lands Commission has told us, it will be releasing the draft environmental impact report to the public later this month after an extensive preparation and review process by the commission. With the release of the draft EIR, other agencies and the public will review the adequacy of the report and submit comments prior to finalizing the report.

The report could be finalized around the third quarter and the approval process would begin with the four different jurisdictions that are involved. We don't expect approval process to be concluded until some time in 2009, and the project would start up immediately thereafter. The first part of project will be construction of 10 mile on shore pipeline to replace the barge along with facilities work both our offshore facility platform Holly and our onshore processing plant.

Actual, drilling from the platform could commence after some of the facilities and the pipeline work is completed, which could be later in 2009. The development program consists of extended reach wells drilled into the eastern portion of the field from our existing platform. As we have discussed before, the project actually reduces infrastructure on the coast by replacing the barge operation that currently transports crude oil to market with a new pipeline.

The new pipeline will connect to an existing segment of the all American pipeline near Exxon's Las Flores Canyon facility. Procuring pipeline write-aways and anticipation of the approval of the project continues and we have initiated certain capital expenditures in that regard. In West Montalvo field, which we acquired last May, we have seen production start to increase in the quarter from both the new well that we drilled late last year and our fluid enhancement efforts thus far.

During the quarter we saw gross oil production climb by about 300 barrels a day after an extensive testing period, the new well has been on permanent production, later on or earlier this quarter and we're currently seen around 200 – 200 barrels net per day of production. Our other production growth has come from returning idle wells back to production and performing various workovers and recompilations.

We've been able to handle the additional fluid volumes from these wells with reactivated injecting wells and insulation of related processing facilities. We are installing new artificial lift equipment, which allows us to increase fluid volumes, increase up time and produce more effectively and efficiently.

Turning to offshore for a moment, as we discuss with last quarters results, we have suspended work on platform Grace until we have reevaluated our geologic model and are drilling and casing designs. We have been able to redeploy that capital to the Sockeye field and efforts to expand the water flood there, including expansion of water handling, injection capacity and fluid handling capacity.

We have seen some very encouraging results from initial efforts in this water flood and are excited about additional water flood in potential that exist in the field. We also continue to evaluate our model into drilling this well which is quite sizable and we also very active in Texas in both our Hastings complex and in the near by Manvel fields, which evolve now for a full year. We continue to focus in both fields and then turning again wells back to production converting gas of wells to ESP electric submersible pumps and adding additional fluid processing and injection capacity.

We've been able to leverage our experience and our redevelopment template from Hastings to the Manvel field quite successfully. Expansion of our fluid handling facilities in Hastings last year, took us from about a 140,000 barrels a day in total in terms of total fluid handling capability to nearly 500,000 a day today, as I mentioned we are adding injection wells also to dispose the resulting water from returning oils to production and are from other well workovers and re-completions that we're doing.

Currently, we have water disposal capacity of about 325,000 barrels per day, we've completed 18 workovers in the first quarter and we have a solid inventory of wells to work on during the balance of the year. We're seeing incremental production increases in both Hastings and Manvel from this work. We continue to make with Denbury resources regarding our options regarding their option to acquire the Hastings complex and implement a CO2 enhanced recovery project. Denbury has a final $5 million option payment due in the fall, which will bring the total of $50 million.

So Denbury has strongly indicated to the market that they pay are likely to exercise in November of this year, their contract provides then the opportunity to wait and exercise in November of 2009. We meet regularly with their technical staff on the CO2 development plan and also to coordinate our activities in the field within as well. Denbury has told market that they would like to have about a year to prepare the fields for CO2 injection and that they anticipate they can complete their pipeline and be ready to deliver CO2 in late 2009.

Assuming they exercise the option to purchase a field, we can either receive a cash payment based on the PV10 value of proved reserves. At the end of their exercise year or we can enter into a volume metric production payment VPP arrangement as well. Currently the cash option make some more sense for us, we provided some parameters in the IPAA presentation to give you some idea, what this project could be worth to Venoco.

Using our year-end 2007 reserves, we believe the sales price would exceed $300 million after netting out some of our below market hedges. We expect to work that we are doing in the complex this year to drive the proved reserve numbers higher and also resulting in a higher cash price. Following Denbury's purchase of the field, Venoco retains an overwriting royalty interest of 2% in the properties and can back into a working interest of approximately 22.3% in the CO2 project after Denbury recoups various costs and expenses.

Denbury's shows the Hastings CO2 project having a PV-10 value to them of about $1.7 billion, if you look at our calculations in the IPAA presentation you see that we estimate the CO2 flood being able to recover about 39 barrels net to Venoco this assumes achieving just the low end of the typical 10% to 20% of the original oil in place factor that we have used for recovery here. Based on the reserve values from our year-end 2007 reserve reports, $30 million barrels could have a PV-10 value of over $700 million but we're using $550 million to $600 million in the presentation.

In our nearby field Manvel, now we have been keeping production flat over the past few months as we get the facilities in place to again ramp up the work over and recompilation program plans we have for that field. Our focus in Manvel as in Hastings is on increasing our fluid processing and injection capacity. We are stepping up our evaluation of the fields as longer tem CO2 opportunities. Since Manvel has the same geologic and reservoir characteristic as Hastings. We now have a CO2 export on our staff and we are encouraged by the discussions we have had with potential CO2 providers and believed our several opportunities to bring CO2 demand well as well.

With this I will turn it back over to Tim and let him talk about the s Sacramento Basin.

Tim Marquez

Thanks Mark. Sacramento Basin remains very active. Since I returned to the company in 2004, we have greatly increased our lease basin primarily in the State's second and third largest gas field primes and oil as respectively. We currently have the 20,000 net acres about a 7 fold increase from the 30,000 we owned in 2004.

Since 2004, we have been the most active drills in basin by far having drilled well over 200 wells. Besides our production increases, these wells are further delineated to play, improved on more 40 acre in sales, improved up 20 acre in sales than we have actually even tested a few 10 acre in sales.

On top of that we have been testing at horizons we have improved up more productions. In our IPAA presentation we surely now believe that the 2P potential based on internal estimates in the Sac Basin is about 500 to 700 Bcf net to the company. That compares to our year end 2007 proved reserves up 166 Bcf.

The potential in the Sacramento Basin is very sign to that account. Our joined work over program continued at full speed during the quarter. We sped 29 wells in the basin and completed about 29 workovers and new completions in the first quarter. We had five drilling rigs active during the quarter along the five workover and completion rigs.

Initial result of the hydraulic fracturing program we began the fourth quarter continues to be encouraging. We now have almost six odd months of data from our first fracs from November 2007. Again I will referring to our IP88 presentation to get more details and look at the type curves we have for the various wells shown within without tracks and historical well completion pro forma basin, particularly Manvel's and grind sand as in the said case incorporate and put the wells on to production.

This works okay in the thicker channels, first of all by the majors and the 50s and 60s. The majorities of wells that are produced are not completed in thick channel sense, depend our over bank 11 sand deposits. These sand lands are small, many instances covering only 10 to 20 acres. By perforating four to six holes per foot, we hope get the majority of these lands, but after acquiring some wells, we know that we could be missing some of the thin sand in the wells between the first.

With fracing, we're hoping to not only reach out from wellbore horizontally to connect to more of these lenders, but also to reach vertically to connect to these center zone that could be lost behind the pipe.

We need more time to understand, how these flats will ultimately perform, but here's what we believe based on the information we have so far. The 40 acre wells of fracs could yield between 0.3 and point – net Bcf per well. For 28 acre wells which were now drilled about 100 of, we estimate there were fracs these wells will be only between 0.3 to 0.7 net Bcf per well.

Too early to say with 10 acre wells could yield. Using fracs complete, re-complete existing wells, we've about 500 existing wells. We estimate oil yield be between 0.1 to 0.2 net Bcf for re-completion. Oil and development cause all of these projects 40 acre wells, 20 acre wells infield fracs and regular natural completions. We estimated a little over 250 per Mcf. We estimate we have around 3,000 projects in total, which include the 20-acre wells to 40-acre wells, and although re-completion opportunities.

We have spent last two years focused on inter drilling both on 40-acre spacing, 20-acre spacing. We have drilled number of wells to evaluate other information's within our leaseholds. With the frac information we update refine our inter drilling to incorporate that drainage we have – can achieve with fracing.

We frac 16 wells in the first quarter and on pace to frac more than 50 wells this year. As the result continues to be positive, we can shift some allocated budget dollars to frac close to 100 wells this year. As I mentioned we have over 500 wells in the basin, of which about 410 of them are active. So, we will be aggressively moving the frac program forward to unlock potential of the field. Most existing wells in the field have multiple zones to the period we frac ended.

Important to note that we don't have any reserves in the field attributive to these type of information's. A successful frac-to-frac program can add a significant amount of reserves to the fields in Sac Basin. All in all, we continue to be very excited about our core operations in the Sac Basin, as well as the tradition opportunities we see in our down space and frac programs. With that I would like to introduce our CFO Tim Ficker, who will go over the financial highlights.

Tim Ficker

Thanks Tim. I just spend a few minutes by covering some financial highlights from the quarter. As you and Mark mentioned we had a great start to the year. The first quarter we have reported adjusted earnings as $16.5 million, which represents a full, fold increase over the fourth quarter of '07. Our adjusted EBITDA for the quarter were $77.5 million or 42% increase over fourth quarter and greater than a 100% increase over the first quarter of '07.

Our oil and gas revenue were a $137 million for the quarter, which is a significant increase over the fourth quarter as well as the first quarter of '07 and our increased revenue was driven by production growth, which was up nearly 5% sequentially to 21,000 – 200,026 barrels per day, barrels equivalent per day and is also driven by commodity prices where we saw nearly $5 per barrel increase in oil and nearly $1 per Mcf increase in gas.

Commodity derivative losses is the other significant component of the revenue section of our income statement. As result of the continuing upward moving in oil prices, we've recognized loss in this category of $74.9 million for the quarter. I'll not that a majority of that amount $54.6 million was due to the unrealized change in fair value of derivatives and $2.1 million is due to non-cash amortization of commodity derivative premiums. Production expenses for the quarter were down from $39.9 million in the fourth quarter to $32 million in the current quarter. BOE basis, BOE component decreased from $18.34 per BOE to 14.68 per BOE. These reductions results from completion of their medial activities in the Hastings Complex along with production volume increases from Hastings and Sac basin.

On the G&A side saw an increase to $9.1 million in the first quarter from $7.1 million in the preceding quarter these increases reflect, increases of our profession staff, increases in stock based compensation as a result of FAS 123R and costs related to settlement of employment contract. On a BOE basis, G&A expenses excluding FAS 123R charges were 409 for the first quarter and we expect our 2008 full year G&A to be $3.75 per BOE excluding FAS 123R charges. On the D&A, we saw a slight increase from $29.3 million in the fourth quarter to $31.2 million in the current quarter and that's driven by increases in our full cost tool which results from our CapEx program

Turning to the balance sheet compared to year end '07, the biggest changes we saw over in commodity and interest derivatives, where we saw sizable increases resulting from increasing commodity prices and decreasing interest rates and also in PP&E which is up as a result of our CapEx program and from small acquisitions in the quarter and debt which was up as a result of this swing in certain of our working capital accounts.

On the debt side I'll also mention a couple of things. First of all last week we amended our revolving credit facility to among other things extend the maturity to March of 2011 and increase the borrowing base from the $140 million to $200 million. The second at quarter end we had $92 million outstanding under our revolver but since then we've been able to pay down $10 million, which brings us back to the balance that we had when we filed our 10-K in early March.

As we've mentioned before in the context of our overall business strategy we would like to see our debt levels in a 2 to 2.5 times EBITDA range and given the solid results from the first quarter and our expectations for reminder the year we believed we can hit that target. That's a brief financial overview Tim, I will turn it back to you.

Tim Marquez

Thanks Tim. With that I would to open up for questions.

Question-and-Answer Session

Operator

(Operator instructions) Our first question comes from the line of Mike Scialla with Thomas Weisel Partners. Please proceed.

Mike Scialla – Thomas Weisel Partners

Good morning guys.

Tim Marquez

Good morning, Mike.

Mike Scialla – Thomas Weisel Partners

Could you say again, I think you mentioned, Mark, the value of Hastings based on more current prices and also is there any chance that you would solve the whole the things including your reversionary interest in the CO2, have you discussed that at all Denbury?

Mark DePuy

I'll answer that. We stated that net of – we want in line some hedges – some underwater hedges for '09 be at the current price beating over $300 million our estimate. As far as the reversionary interest, I mean anything's fair gain, but certainly no firm plans. At least I don't know if the guys working on this have talked about that, but any fair gain, but I doubt – my guess is I doubt we could realize the full value that we see in the CO2 upside.

Mike Scialla – Thomas Weisel Partners

Okay, that's fair. And the West Montalvo that extension well, that came on at 400 barrels a day, how's that compared to your pre-drill expectations, and I am sorry if I miss it, but when do you plan to spud the next extension there?

Tim Marquez

I will take that one. Yes, it's fairly close to our pre-drill expectations that came in over 400 barrels a day. It is currently producing 350, this is gross numbers now, probably close to 300 to 350 barrels a day gross right now. So, it came in pretty close. We actually have a second location already identified offshore. We do have plans to drill a couple of onshore infill wells, but we're probably – we also have plans to do some 3D over both the onshore and the offshore portion, and we will probably wait until we have the 3D done before we drill the second well, offshore that is.

Mike Scialla – Thomas Weisel Partners

Right, okay. And then as you look at the Sacramento Basin – I guess in terms of your budget you said that the current prices hold up, you may be increasing the budget, where would the increase most likely be, is that Sac Basin or elsewhere?

Mark DePuy

Yes, it would probably go to Sac Basin. We had some unallocated budget money including the $335 million that we probably shipped over to the fracs, but we could perhaps ramp some more up Sac Basin by the end of the year.

Mike Scialla – Thomas Weisel Partners

So it would most likely go to more fracs or infill drilling or kind of a mix?

Mark DePuy

Well, the unallocated budget amount would go to probably fracs whereas if we actually increased the budget itself, that would probably go towards more drilling and workovers.

Mike Scialla – Thomas Weisel Partners

Okay, thanks. I will get back in the queue.

Mark DePuy

Sure, Mike.

Operator

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

Joe Allman – JPMorgan

Good morning everybody.

Mark DePuy

Good morning, Joe.

Joe Allman – JPMorgan

I guess this might be for Tim Ficker. Tim, in your press release you said you spent $70.5 million and when I look at the 10-Q, it looks like you spent $81 million plus on oil and gas expenditures. What would be the delta there?

Tim Ficker

It is just our change in accruals from where we were at year end, we had significant accruals at year end, and we had less accruals at the quarter end. So really it is paying for the costs that we incurred in the fourth quarter. So that is really just the difference between our cash on the cash flow statement and what our actual spend was during the quarter.

Joe Allman – JPMorgan

Okay, that's helpful. And then also on production I know there were a couple of adjustments to production in the press release, so basically do we take the number that is in the 21,026 and then subtract 390 and then add 125 to get what the true production was during the quarter?

Tim Ficker

That's correct. I think that if you take the table in the press release for Sacramento you would back out the 390. And then for the Southern California, you would add in the 125.

Joe Allman – JPMorgan

Got you, thanks. And in terms of the budget, it looks like – maybe you said this. I'm sorry if I missed it. But it looks like you are ahead of schedule in terms of if you were to annualize the first quarter spending, that would be higher than what your current budget is. What are you thinking about in terms of increasing the budget here?

Tim Marquez

The principal reason that we are ahead, if you just annualize we are ahead is because that's most of the workovers and Hastings are front end loaded the first half of the year. So that was always planned to spend the bulk of capital in the first half of the year.

Joe Allman – JPMorgan

Okay, that's helpful. And then lastly, what are you guys seeing with drilling and complete costs these days? What is the trend you are seeing, and have you seen a change recently?

Tim Marquez

It is so hard to say, but I would say our feeling is that we are holding our costs in Sac Basin pretty steady. I know some people reporting decreases and we really haven't seen that. In fact, we still continue to see some increases. But we've gotten more efficient with our drill and we've definitely gotten – been able to cut our drilling time in Sacramento Basin in particular, where we do most of our drilling. So net-net is we are seeing drilling costs stay pretty constant. Fracing is new, so we have nothing to – at least in Sacramento Basin it's new, so we have nothing to compare there. So all in all I would say pretty constant.

Joe Allman – JPMorgan

Okay, very helpful. Thank you.

Operator

Our next question comes from the line of Jeff Robertson with Lehman Brothers. Please proceed.

Jeff Robertson – Lehman Brothers

Thanks. Tim, can you talk a little bit about the maintenance plans you all have during the second quarter for your offshore California assets and what that involves and how long you expect some of that production to be off?

Tim Marquez

Yes, we have actually completed the maintenance work for Platform Gail. That is the Sockeye Field in the first part of the second quarter. That was down what, Mark, about four, five days?

Mark DePuy

Four, five days, yes.

Tim Marquez

And then on Platform Holly at the end of the second quarter we anticipate that going down about two weeks. So that should hit our average production to the company net by about 500 barrels a day having that down for two weeks. Some of that work is just general maintenance. Some of it is actually prep work in anticipation of getting permits for oilfield development next year. So, just trying to get as much done as we can in that two weeks.

Jeff Robertson – Lehman Brothers

And on the draft to EIR, you said that you think that will be – you will hear something back on that in the third quarter, is that correct?

Tim Marquez

Yes, where we stand now is the draft EIR, there is a draft that has been received by the State Lands Commission for some time, and they have actually been tinkering around with it. But that draft EIR will come out this month. Then there is a comment period and then the EIR itself should be finalized and hopefully approved by some agencies even this year.

Jeff Robertson – Lehman Brothers

And the EIR, Tim, that mainly covers the infrastructure that you all are talking about, which actually has a positive environmental impact because of the elimination of the barge, right?

Tim Marquez

Yes, I mean it does a lot of things. Actually this is a project that you really – there really is no argument against it. It certainly gets rid of the barge at South Ellwood and allows for the pipeline to connect to All-American pipeline system. That barge has always been a thorn in the side of the County, so that satisfies that. The drilling out there also actually accelerates the field. In other words, we are right now draining half the field that hasn't been drilled. But we are actively draining it right now, and given enough time, our models show that we could probably drain 80% plus of it from the existing leases.

However, that is going to take you a long period of time. By drilling in this lease extension area, it actually accelerates the field life, so it shortens the field life which is another big impact. And then maybe not such an environmental impact, but certainly any drilling done on the lease extension area, the County would get a share in 20% of the royalties. So if we don't drill it, we'll just continue to drain from the existing leases, then the County is going to lose out on, well it appears to be at these prices, well over $100 million. So they have – should be very motivated to approve this since there is really no downside.

Jeff Robertson – Lehman Brothers

Thank you.

Tim Marquez

Sure, Jeff.

Operator

Our next question comes from the line of Steve Berman with Pritchard Capital Partners. Please proceed.

Steve Berman – Pritchard Capital Partners

Good morning. Just a quick clarification, Tim. The flat production you're talking about Q2 versus Q1, is that versus the 21,026 or the 20,700 plus after adjusting for the true up?

Tim Marquez

Yes, versus 21,026.

Steve Berman – Pritchard Capital Partners

Okay, that's it. Thank you.

Operator

Our next question comes from the line of Biju Perincheril with Jefferies & Co. Please proceed.

Biju Perincheril – Jefferies & Co.

Can you talk a little bit about the use of proceeds from the Hastings transaction, when that is completed, given your debt to cap is in the mid '70s range? And some significant CapEx coming up with the Hastings program and also opportunities to ramp up Sac Basin?

Tim Marquez

Yes, mechanically I think 50% of the proceeds from Hastings has to be offered to the term loan holders. The rest will be paid – used to pay down the senior debt. We anticipate doing some more acquisitions this year. As we said, we can't budget to acquisitions. I can tell you we are very, very active in the acquisition market and we really stepped up our activities there, built up our staff there. So, we had hoped to be able to do some significant acquisitions this year, but that is out of our control really. But yes, as I said, it is also possible that we would step up our drilling in Sacramento Basin. I think we said at IPAA, when you have roughly 1000 well inventory at our current drilling rates, that would take us almost ten years, eight to ten years to drill that up, and that is not efficient. So we do need to start picking up the pace in Sacramento Basin just to be more efficient and increase the present value of those assets up there.

Biju Perincheril – Jefferies & Co.

Okay, thanks. And then the acquisition opportunities that you're looking at, are these more onshore California or are you looking at increasing your presence in the Gulf Coast?

Tim Marquez

Well, yes to both, but I would say probably 70% of our efforts are focused in California, with the bulk of that focus being Southern California. We now have rounded up the easier stuff in Sacramento Basin because there is not a lot of big targets left up there, but yes, big focus of ours is Southern California. We are predominately an oil company. We love these long life California fields but we do also have a very significant focus in Texas Gulf Coast, particularly the mature waterfloods and any other play that would play to our strength. We like these reservoirs like in Sacramento Basin, these low resistivity reservoirs that other people have left behind, and we see some opportunities not only in California but around the country with some things like that. And these mature waterfloods, we consider ourselves to be pretty efficient at handling these big floods. And a lot of people had given up Hastings for dead, but we've been able to greatly increase production and pipe down [ph] the expenses and we think that is a particular niche of ours.

Biju Perincheril – Jefferies & Co.

Okay, perfect. Thank you.

Operator

Our next question comes as a follow-up from the line of Mike Scialla.

Mike Scialla – Thomas Weisel Partners

Just wanted to get a little more detail on the fracs. How many of those have targeted the Guinda at this point and what do you see as the potential there, and can you produce the Guinda together with the Forbes?

Tim Marquez

We frac-ed our first two Guinda wells last week. The wells are clean enough so we don't have any results on those wells. But at least mechanically we got the fracs away. So that is a positive. We did – by the end of this year, our team understands that I want them to evaluate 20 to 30 Guinda wells before the year is up. So, by the end of the year we will have a lot more information, but I do not have anything real positive to tell you. But we have been seeing some more encouraging results. We've actually had at least one Guinda well come in pretty stoutly without a frac, but we are very encouraged. We think we've got the Guinda pretty well mapped where it is prospective and not prospective. There has been a lot of penetrations at least into the top of Guinda, but people have always been scared of it because it is very much an over-pressured reservoir. As far as commingling with the Forbes, yes, there is no reason we couldn't commingle them together.

Mike Scialla – Thomas Weisel Partners

Okay. And at South Ellwood, how much of that right-of-way for the pipeline do you have at this point?

Tim Marquez

Actually, secured it as a pretty small percent, but there is not that many landowners along the way, and we've been in discussions with every one of them. I don't see that there is going to be any real major hang-ups there, and I would think by third, fourth quarter this year that we will secure the bulk of those. Things are moving ahead pretty nicely. In fact, we've given the team the go ahead to accelerate the pace there because things seem to be – we are pretty encouraged by what we are seeing from the regulatory bodies here in the County and the State.

Mike Scialla – Thomas Weisel Partners

So, it's kind of working the same sort of time line as the EIR?

Tim Marquez

Yes, correct.

Mike Scialla – Thomas Weisel Partners

Okay. And then, and one last one. Any postmortem on Grace? I know you put it on the back burner. Is it going to stay there for a while or have you guys kind of reevaluated what you think happened with those wells, and is there any potential to go back in there at some point down the line?

Tim Marquez

That is a good question, Mike, and actually we are encouraged. As you recall, we drilled three wells. One looked like a good well, but at the bottom of the well, we crossed over into a fault and that fault we believe is channeled water that just overwhelmed the well. Now, we believe that we could go back and re-drill that well and stabilize the fault and we think that well, based on a lot response that should be a good well. We had one other well that was turned out fine, is making a couple of hundred barrels a day and still cleaning up. And then the casing collapse, that field has never seen a casing collapse so that was a head scratcher why we saw that casing collapse. But that was a good well. The third well initially was a real head scratcher. It looked good, but it tested wet. Well, that well has cleaned up and it is actually producing about 100 barrels a day, which isn't great, but it is also the pump in the well is undersized. So at some point, we're going to go in and put a bigger pump and see what that well can do. So, actually as we said all along, we still felt the project was economic. It is just that we had so many other projects, particularly Hastings, Sac Basin that are better much better. So yes, a long-winded way of answering your question, yes, I would guess that we will get back in that field because it was economic. When I say it was economic, it had good, strong economics actually at $80 price deck, and unless prices collapsed over last hour, they are still quite a bit above $80. So it is a nice project. It is just I think people, maybe we explained it wrong, but it is just we had so many other projects that had better economics we decided to redeploy our capital to the stronger economic properties. But that project I think will get back on sometime probably won't be this year, but I would guess next year we will get back after it.

Mike Scialla – Thomas Weisel Partners

Okay. Thanks, Tim.

Tim Marquez

Sure.

Operator

(Operator instructions) We have a follow-up from the line of Joe Allman. Please proceed.

Joe Allman – JPMorgan

Yes, thank you. Tim, any thoughts on the Plains transaction regarding its offshore operations and how that might impact you offshore?

Tim Marquez

The feeling around here is it wasn't that significant. We've been saying all along that we are pretty optimistic about getting our permits done. Our project is a lot different than theirs were. As we discussed earlier, we are already providing a lot of environmental impact including accelerating the life of the field which is something the environmentalists want. I can't see us in any way shape or form getting – I think their deal calls for one field they agreed to sunset date eight years and another one 14 years. That is a non-starter for us. First of all, I don't think we need it because we are already short in the field life. I think in general I would say it is more positive than negative that the environmentalists are willing to finally have a little bit of reason. I mean, we have known all these – Linda Krop and all these people for many, many years and carry on active dialogue. We understand what they want and I think they understand what we want. And maybe everybody is maturing a little bit that we can actually sit down without killing each other. But I think it is a general positive and we have good relationships with all these environmental groups. Not that they particularly like producing oil offshore but I think they know that it is better to salvage something than nothing. So I think it is generally, it's positive.

Joe Allman – JPMorgan

Okay. Thanks, Tim.

Tim Marquez

Sure.

Operator

There are no further questions at this time.

Tim Marquez

Thanks everybody for joining us for the first quarter conference call. We look forward to talking to you about our second quarter conference call here in a few months, and hopefully we can keep things going upward and onwards. Thanks a lot for joining us.

Operator

This concludes the presentation. You may now disconnect and have a great day.

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