Venoco, Inc. Q2 2008 Earnings Call Transcript

| About: Venoco, Inc. (VQ)

Venoco, Inc. (NYSE:VQ)

Q2 2008 Earnings Call Transcript

August 7, 2008 11:00 am ET


Mike Edwards – VP, IR

Tim Marquez – Chairman and CEO

Mark DePuy – COO

Mike Wracher [ph] – Exploration Manager

Tim Ficker – CFO


Mike Scialla – Thomas Weisel Partners

Biju Perincheril – Jefferies & Company


Good day, ladies and gentlemen. Welcome to the second quarter 2008 Venoco Incorporated earnings conference call. My name is Marsha, and I will be your coordinator for today’s call. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session toward 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 Mr. Mike Edwards, Vice President. Please proceed, sir.

Mike Edwards

Thank you. Hello, everyone. Venoco issued a press release today on our second quarter 2008 results. We also filed our second quarter Form 10-Q with the SEC. On the call today to discuss the second 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, allow me to make a couple of comments regarding forward-looking statements. All 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 Act of 1933 and Section 21E 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 the 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 potentially be recovered 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 control, including, but not limited, to the exercise of the option of purchase, the implementation of a 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 risks and uncertainties related to forward-looking statements are set forth in our filings with the Securities and Exchange Commission. The earnings released and the relevant non-GAAP reconciliations are available on the Investor Relations page of the Venoco Web site, which is

Now, I’d like to introduce Venoco’s Chairman and CEO, Tim Marquez.

Tim Marquez

Thanks, Mike. And welcome, everybody who’s called in or looking into the webcast. Today, I’m pleased to review Venoco’s second quarter results. We’ll dive right in. Starting with our production, our average daily production volume for the quarter was 21,033 barrels oil equivalent per day, which as we discussed in our first quarter call, flat with the first quarter production of 21,026 BOE per day. We expect the production to be flat as we have scheduled downtime related to planned maintenance for several weeks at our South Ellwood Field and at Sockeye in Beverly Hills. We believe the net impact of this downtime on the same quarter production was about 500 BOE per day.

I’ll remind you that we had a one-time true up in the first quarter productions for Sacramento Basin interest and royalty allocation in Southern California. So the actual volume produced in the first quarter was 20,760 BOE per day. Compare that actual production first quarter to second quarter production and adjust for downtime, you’ll see that we would have been up about 770 BOE per day. Our forecast for the balance of the year is for production to trend upwards company wide. Reported production for the second quarter was up 7% year-over-year for second quarter 2007. Q1 to Q2, the lower production in Southern California due to our planned maintenance work was more than offset by higher production both in Sac Basin and Texas.

We continue to confirm our production guidance for 2008 production of 20,500 to 21,500 BOE per day. As I said on the year-end call in March, we believe we’ve been conservative in setting this production guidance, and our very folks stopped beating it. During the third quarter, we expect to be back to full capacity and anticipate production will be higher for the balance of the year relative to the first six months.

Turning to capital expenditures, for the second quarter, capital expenditures were $78.6 million, with about 55% spent in the Sacramento Basin, 22% Southern California, and the balance of 16% in Texas. For the first six months of this year, our capital expenditures were $142.3 million, ahead of pace for our $235 million capital plan for the year. This is due primarily to expediting our frac program in the Sac Basin, additional facility CapEx to complete our upgrade in Hastings, and capitalize G&A. As we have discussed back in May, our intention is to maintain a capital program keeping pace with cash flow.

We’ve continued a high gas and oil price levels, good performance year-to-date, and ready inventory of additional growth opportunities. We’re considering increased start CapEx budget later this year.

We continue to actively pursue acquisitions, which lend themselves strategically to our strengths, exploiting underdeveloped assets, mature water floods, and unconventional reservoirs. Although we are very active and aggressive, we’ll not make acquisitions to achieve growth.

Second quarter released operating expenses and G&A costs of – for the second quarter, lease operating expenses were $15.40 per BOE, which is an increase of 5% from the first quarter of 2008 of $14.68 per barrel. The increase in the second quarter expense is primarily due to higher electricity and maintenance cost, most of which was associated with our planned shutdown. I’ll let Tim Ficker, our CFO, discuss that further in just a little bit.

We expect to see LOE expenses of $15.50 per BOE for the full year 2008, unchanged from our annual guidance provided earlier this year. Second quarter G&A expenses were $6.36 per BOE, but excluding FAS 123R charges and the one-time charge we incurred in the second quarter when we – which is due to our application to form an MLP, our G&A was $4.39 per BOE.

I’ll let Tim Ficker go into more detail in the G&A expenses. But now, I’d like Mark DePuy, our Chief Operating Officer, to discuss field performance.

Mark DePuy

Thank you, Tim. I’ll start with Southern California. From the South Ellwood field, the State Lands Commissioner released the draft environmental impact report to the public in June after an extensive preparation and review process by the Commissioner. With the release of the draft EIR, other agencies and the public will review the adequacy of the report, and submit any comments prior to finalizing the report. All comments are due in by August 24, and the report can be finalized at that time. We anticipate the final EIR late in the fourth quarter of this year.

The approval process will begin with the four jurisdictions that are involved, starting we expect with a hearing before the lead agency, the California State Lands Commission, in December. After approval by the State Lands Commission, other jurisdictions, principally in the county of Santa Barbara and the city of Galeda, can schedule hearings. We expect the approval process to be completed early to mid 2009. After which, the project would be ready immediate startup.

Our first item in the project is the construction of a 10-mile onshore pipeline, along with some facility work, both at our onshore processing plants and on platform Holly. Actual drillings on the platform could commence after some of the facilities and the pipeline work are completed, which we will hope – which we hope will be in the second half of 2009. The development program consists of wells drilled in the Eastern portion of the field using our existing platform and extended reach drilling technology. I want to emphasize that the project actually reduces infrastructure on the coast by replacing the barge operation that currently transports our crude oil in the market with the 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 are initiating certain capital expenditures for some of the long lead items.

In the West Montalvo field, we have seen production increased nearly 40% or about 270 barrels equivalent per day at year-to-date as a result of our ongoing efforts returning idle wells production, upsizing our lift capacity, and upgrading surface facilities. Installation of new artificial lift equipment has allowed us to increase fluid volumes, increase are up time, and also produce more efficiently. In addition to continuing with well work projects, we intend to initiate drilling one to two in-field wells onshore in the second half of this year. We are also continuing with plans to do a 3D seismic survey over our acreage later on this year as well.

Turning to offshore, as we discussed with the first quarter’s results, we focused our capital expenditures of platform Gail where we have completed a number of work-overs that have allowed us to expand the water flood in the field and maximize production with higher rates, more efficient electric submersible pump conversions. The expansion of the water injection and fluid handling capacity, we’ve been able to increase both gross fluids and net oil from the field.

This is an acquisition that we made way back in 1999 that demonstrates, once again, how much potential remains in these types of assets that are considered non-core to many of the majors. The Sockeye field is a typical example of the kind of asset the Venoco likes, and can be very successful at redeveloping. Following the acquisition, the first reserve report that we actually generated predicted that we’ll only be making 23,000 barrels a day by 2008. Current production is more than double this amount. And once again, demonstrates the beauty of this large California fields that we own. They have tremendous potential, lots of upside, and we’ve been able to unlock this with time.

In Texas, the news is consistent with the first quarter in that we remained very active in both our Hastings complex and in the nearby Manvel field, which we acquired in April of 2007. Our approach has been getting back to the basics, nothing terribly glamorous here, but still, nonetheless, economically very attractive. We remain focused on returning wells to production, converting gas with wells to electric submersible pumps, and adding fluid processing and injection capacity. Both fields have seen production increases as a result of these efforts, with Hastings up over 200 barrels a day net, or 9% year-to-date, and Manvel up 140 barrels a day net, or about 24% year-to-date. We continued to run with four to five work-over rigs at Hastings, and we have a strong inventory of wells to work on for the balance of the year as well as going forward.

All in all, the slow work has been very successful, which has led to significant increases and improved reserves as well. We continue to meet with Denbury Resources regarding their option to acquire the Hastings complex and implement a CO2 enhanced recovery project where there is a final $5 million option payment due in November. Denbury is required by our agreement to notify us on September 1st if they’re going to exercise the option this year. While Denbury has indicated they are looking very hard at exercising this year, the contract provides them the opportunity to wait and exercise in 2009, September again, 2009 without additional option payments. We continue to meet regularly with their technical staff on the field to development plan, and to coordinate our activities in the field.

Assuming they exercise the option to purchase the field, we are likely to choose the cash payment based on the PV10 at year-end of their exercise year rather than our option to enter into a volumetric production payment arrangement. We’ve provided some parameters on the value of the project of Venoco in recent Street and analysts presentations without attempting to update our year-end 2007 reserve number with a $97 per barrel oil price. Even with those numbers, we expect the exercise price to exceed $300 million. We believe the work we have completed this year and are continuing to do on the complex have pushed reserves up by more than 25%, and can go yet higher by year-end.

Following Denbury’s purchase of the field, Venoco retains an overriding royalty interest of 2% in the properties. And we can back into a working interest of approximately 22% in the CO2 project, after Denbury recoups various costs and expenses. Denbury shows the Hastings CO2 project having a PV10 value to them of about $1.7 billion. If you look at our calculations and recent presentations, you see that we estimate the CO2 flood being able to recover abut 30 million barrels net to Venoco. That assumes achieving only the low-end of the typical 10% to 20% of the original oil in place recovery factor.

In presentations where we have used $97 oil, we’ve estimated our PV10 value for this back in interest to be between $550 million to $600 million. The Manvel field, which is about four miles away from Hastings, presents a similar opportunity as Hastings with CO2 flooding potential because of its similar reservoir and fluid characteristics. We now have a CO2 expert in-house, and are encouraged by discussions we’ve had with potential CO2 providers. And we believe there are many opportunities, several opportunities, for us to bring CO2 to Manvel as well.

With this, I’ll turn it back over to Tim to talk about the Sacramento Basin.

Tim Marquez

Thanks, Mark. We continue to be very active in the Sacramento Basin, and still remain excited about the results we’re seeing and the potential of the basin. We’ve increased our acreage position in the basin to about 200,000 net acres. And that number continues to rise. We’ve been currently operating with five drill rigs, five work-over completion rigs. We’ll try to go more than 110 wells in the basin as planned under our 2008 capital budget. During the second quarter, we spotted 30 wells, and had 26 work-overs and re-completions, bringing our total to 59 wells and 55 work-overs and re-completions for the first half of the year. We drilled a few more exploratory wells outside of our core Northern Forbes development program as well as in the (inaudible) delta during the quarter, which required us to divert two of our drilling rigs away from part of our in-field drilling program in the Greater Grimes and Willows fields.

Overall, report of production second quarter is up slightly from first quarter. But after adjusting for the true up we had in quarter one, actual production was up about 450 BOE per day, about 2.7 million MCF per day. However, as a result of diverting the two rigs to exploratory wells, growth from Q1 to Q2 is slower that what we saw from Q4 to Q1. Moving the rigs back to our development program in the second half of the year should continue to ramp up that program, though, the production in the Northern Forbes.

I understand the frac program also progressed quite nicely during the quarter. We’ve now fraced 35 wells during 2008, plus the three we fraced at the end of 2007. We’ve used a variety of techniques in an effort to better understand the science and get smarter about it all the time. We now have six to seven months of data on some of the first wells we fraced, and so feeling better about the reserve adds from this program. We continue to be encouraged by the results of the program. And plan to frac more than 60 wells in the basin during the year. We believe the fracs will unlock additional reserves and existing zones, as well as tighter, deeper zones. As example, the frac program can add a significant amount of reserves to fill up in the Sac Basin.

I’d also like to give an update on 20-acre spacing in our wells. We’ve now drilled a total of about 120-acre wells, including wells last year and this year. And we now, in our minds, still the 20 acres are a proof that we feel good about the reserve potential for the 20 acres that we’ve previously disclosed. Furthermore, we drilled about 10 10-acre wells. And although these are still in the experimental stage, they’re about worth the 20 acres in-fields where a year ago we’re encouraged by the initial results, but not ready to make any bold predictions yet there. But we are pleased with the results so far.

I’d also like to remind everybody to just put these all in perspective, again, about our success in the Sac Basin. When we purchased wells in Grimes from Mobile more than 10 years ago, gross production was about 4 million cubic feet per day. The forecast showed that two fields should be nearly at the end of their lives by now here in 2008. But here we are in 2008 and with our interpretation of the geology, extent of development drilling, strategic acquisitions, we have now increased gross production to over 80 million cubic feet per day. And potential from these fields is greater today than ever before. All in all, we continue to be very excited about our core operations in the Sac Basin as well as additional opportunities we see in our down states in the frac programs.

Turning to exploration, with regard to exploration, we’ve always said that we (inaudible) about 10% to 15% towards exploration. We intentionally haven’t talked too much about this in the past, but we’d like to provide a little more color today. We’ve been actively building acreage positions in several basins new to Venoco that played our core common (inaudible) as well as expanding our position in the Sacramento Basin. Because we’re still in the competitive situation in particular basins, we won’t be going into detail in some of these. We’ve identified specific initial drilling targets and our permitting process, we hope to spot one or more exploratory wells by the end of the year. Add these projects and our leasing efforts in other areas, so we hope to be able discuss other project areas later this year.

I’ll now turn it over to our exploration manager, Mike Wracher [ph], to give you some insights into our exploration efforts.

Mike Wracher

Thank you, Tim. Our exploration group is primarily focused on two areas where we see a strategic advantage for Venoco. The first is the extensive expertise that we have related to fractured shale place. This is derived primarily from working our fields in the Santa Barbara channel. And those are South Ellwood, Sockeye, and the Santa Clara offshore field as well as many others around the state that we’ve worked for Venoco and in previous working lives. The Monterey Shale is the primary source rock for all the Southern California basins, and is some cases, the primary reservoir. And is a valid target in and around our existing operations.

Our other strategic advantage is geographic in nature. Specifically, we target areas near our existing operations where we have developed specialized geologic and engineering knowledge, and have a business advantage. In some instances, we have exploration targets that played at both of those advantages, geographic and fractured shale expertise.

The exploration group has a rapidly growing inventory of opportunities in the nature of land and prospects. We currently control nearly 280,000 acres containing projects in various stages of maturity. As Tim said, we will be able to discuss some of these more fully in the future as they mature and become more secure. However, a few we can discuss today.

The first is our Rainier [ph] and Adams prospects in the Pacific Northwest. In this project area, we now have close to 200,000 acres, and our first prospect is ready to drill. The Rainier prospect is a large anticline with four-way closure containing ESE [ph] and source rocks and reservoirs. This large opportunity has upside of 500 BCF. We are currently looking for partners, and anticipate spreading the well the first quarter of – I’m sorry, the fourth quarter of this year or the first quarter of ’09. This project is within striking distance of our Sac Valley operations and will be a natural fit for that group if we are successful. We are also partners in a well in Zapata County, Texas that will spread the fourth quarter of this year. And again, would be run by our local Houston office if successful.

And now, I’d like to introduce our CFO, Tim Ficker, who will go over the financial highlights.

Tim Ficker

Thanks, Mike. I’ll briefly cover some financial highlights for the quarter, focusing primarily on Q2 versus Q1. Looking at earnings for the second quarter, I’ll note that we had a $325 million non-cash fair value adjustment for our commodity derivatives, or term $1.5 million after tax. When we adjust for VAT as well as the non-cash gain on interest rate derivatives, and a one-time charge for the write-off of costs associated with our withdrawn MLP, we generated adjusted earnings of $22.4 million for the second quarter, which is a 36% increase over the first quarter.

Our adjusted EBITDA was $84 million for the second quarter, compared to $77.5 million for the first quarter. Our second quarter adjusted EBITDA was also impacted by the one-time MLP write-off. We expect to see continued growth in adjusted EBITDA throughout 2008 as we realize expected production increases.

Our oil and gas revenues were $167.1 million for the quarter, which represents the 22% increase over the first quarter. As Tim already mentioned, production quarter-to-quarter was flat as expected. So our increase in revenue was driven by commodity prices where we saw an increase in our realized oil prices of over $23 per barrel, and an increase in the realized gas price of about $2.50 compared to the first quarter.

Production expenses increased slightly from $32 million in the first quarter to $33.1 million in the current quarter. On a per BOE basis, the LOE component increased from $14.68 per BOE to $15.40 per BOE in the second quarter. I want to remind everyone that the first quarter per BOE figure was positively impacted by a production true up of 265 BOE net per day. And the second quarter’s figure includes additional expenses related to our planned maintenance as well as reduced production during that downtime. So in a more apples-to-apples basis, per BOE amounts would be more consistent quarter-to-quarter.

G&A for the quarter increased to $12.2 million from $9.1 million in the first quarter, and $2.7 million of that increase is the result of the non – or the one-time write-off of deferred cost in connection with our decision to withdraw on the Form S1 we filed earlier in the year for the formation of an MLP. Due to the attractiveness of the development projects and our materials long liability sales, high commodity prices, and changing capital market conditions, we saw a little incentive to continue to pursue the MLP. On a BOE basis, G&A expenses excluding FAS 123R charges and the MLP write-off were 439 in the second quarter, and 409 in the first quarter. As a result of increases in our professional staff and related infrastructure made to accommodate our growth, we’ve increased our guidance for the full year 2008 for BOE G&A expense, excluding non-cash FAS 123R charges and unusual items, to $4.25.

Commodity derivatives gains and losses is the other significant component of our income statement. As a result of the significant upward movement in oil prices at quarter end, we recognize the loss in this category of $364.8 million for the quarter. A majority of that amount, $325.2 million, was due to the unrealized change in fair value derivatives, and $1.8 million is due to non-cash amortization of commodity derivative premiums.

When we look at the balance sheet, our biggest changes were in PP&E, which is up as a result of our CapEx program and some small acquisitions; debt, which is up as a result of the swing in certain of our working capital accounts; and, commodity and interest derivatives, where we saw a sizeable increases resulting from increasing commodity prices, which were slightly offset by increasing interest rates.

That’s a brief overview of the financial quarter. Tim, I’ll turn it back to you.

Tim Marquez

Thanks, Tim. Thanks everybody for listening in on today’s call. We’re pleased with our second quarter results and where we are mid year. I feel we’re at a real turning point for Venoco. The next 12 months have great potential to – let’s go the Q&A. Sorry, I’m getting ahead of myself. With that, let’s open up for questions. And then I’ll wrap it up with that gripping conclusions.

Question-and-Answer Session


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

Mike Scialla – Thomas Weisel Partners

Hi, guys.

Tim Marquez

Hi, Mike.

Mark DePuy

Hi, Mike.

Mike Scialla – Thomas Weisel Partners

On West Montalvo, you mentioned a couple of in-field wells you plan to drill there, and the extension well that you said is doing more than 400 barrels a day, or I guess came on more than 400 barrels a day. What is that producing now? And do you have any plans to try another extension well there?

Tim Marquez

The current well’s making about 200 barrels a day still. And the two in-field wells that we’re looking at – yes, this field was originally a drill, although I’ll be at barely loosely on 80-acre grader spacing. And we’re looking at further in-fields down to 40-acre potential. And with these two wells, pending their success, we’ve got many, many more wells that we could follow up on and anticipate a much more active drilling program going forward, to be quite honest.

Mike Scialla – Thomas Weisel Partners

We are more focused on the in-field than trying to extend the field further offshore.

Mark DePuy

At this juncture, yes. As I mentioned, we are going to be running the 3D seismic survey. We’ve decided to wait until we get that survey completed before we go ahead and, I’ll say, design and grow further offshore.

Mike Scialla – Thomas Weisel Partners

Yes. It makes sense. And in terms of the maintenance at South Ellwood in Sockeye, what was done there? And is this kind of a one-time issue or is it something you need to do periodically, every year or so?

Mark DePuy

Every year, for the most part, we do have some sort of planned shutdown for various maintenance and repair work. So this is nothing extraordinary or different from that. A lot of the work that we did here is vessel inspection type work, and then we’ve also did some facility modifications and preparation hookups to allow us to completely dispose of our water at Ellwood from the platform, rather than sending the water to shore for disposal. And we’re very near having that completed. And that was, I’ll say, a good portion of the, at least, Ellwood maintenance this year.

Mike Scialla – Thomas Weisel Partners

Okay. And then in terms of your expiration plays at the Rainier prospect, what is the target there? Is that a tight gas sand? And can you just talk about a little bit more about that, I mean the depth and what you think the exploratory well would cost?

Tim Ficker

That is going after a conventional reservoir. It’s a sandstone reservoir, high probability, high (inaudible) that’s found in the nearby Mitts [ph] field. We expect dry hole cost to be around $1.8 million.

Mike Scialla – Thomas Weisel Partners

Okay. And you said the potential there you thought was 500 BCF, is that right?

Tim Ficker

That’s the upside potential, that’s right.

Mike Scialla – Thomas Weisel Partners

Okay. And then in terms of your Zapata County prospect, is that a Wilcox or level test, and what’s the potential there?

Tim Ficker

It’s a Wilcox test. It’s potential’s 90 BCF, but we’re a junior that well. So the net to Venoco would be about 10 BCF.

Mike Scialla – Thomas Weisel Partners

Okay. I’ll be back in the queue and let others ask. Thanks.

Tim Marquez

Thanks, Mike.


And your next question comes from the line of Biju Perincheril from Jefferies & Company. Please proceed.

Biju Perincheril – Jefferies & Company

Hi, good morning. You talked about the reserves going up about 25% at Hastings. Have you done a new PV10 number that you can share with us?

Mark DePuy

We’ve run some internal models. We don’t like to disclose those figure numbers. And keep in mind we’re in discussions with Denbury. So we really need to avoid those discussions right now.

Biju Perincheril – Jefferies & Company

Okay. Fair enough. And then, if Denbury exercises their option this year, your proceeds – I think you mentioned in the past that about half of it would go to – pay down debt. With the remainder, how much of that would go to buying out the hedges that you have?

Tim Ficker

Well, we’ve said about half would go down to paying down the debt. I’m talking about after tax proceeds. About half would go down to paying down debt, and half would go towards new winding the hedges.

Biju Perincheril – Jefferies & Company

Okay. And then, if you look at the potential CapEx – is it fair to say most of that would go to Sac Basin activities?

Tim Ficker

It’ll be spread around quite a bit, fairly equally, really, the different areas. And probably a disproportional amount will go to South Ellwood, just in anticipation of getting permits next year. We would like to – we feel confident enough that we’ll get the permits next year. Then we’re going to start spending some money this year as Mark mentioned.

Biju Perincheril – Jefferies & Company

Okay. Fair enough. Thanks a lot, guys. Thanks.


(Operator instructions) And we have no further questions at this time. I would like to now turn the call back over to Mr. Tim Marquez. Please proceed.

Tim Marquez

As I was saying before I interrupted myself, we’re at a real turning point for Venoco. The next 12 months is really going to be transformational as a company. As we said, we’re very excited about Venoco’s South Ellwood full field developmental project. Again, some significant milestones and through first quarter next year. The Hastings deal with Denbury will hit a milestone about three weeks as we expect to hear from Denbury regarding their exercise. Commodity price have increased our anticipated cash flows. We’re evaluating increase in our CapEx later this year. After six months, we’re within our production guidance range, and continue to be focused on coming out on our head or higher. Our exploration projects are coming together and expect to spread some wells by year-end, possibly in several areas. And Sacramento Basin continues to produce new opportunities and increasing growth opportunities.

Thanks, everybody, for joining in. And I look forward to discussing our third quarter conference call in a few months here.


Thank you for your participation in today’s conference. This concludes the presentation. You many now disconnect. Good day.

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