Good day, ladies and gentlemen, and welcome to the First Quarter 2012 Berry Petroleum Company Earnings Conference Call. My name is Tom, and I will be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to Bob Heinemann, President and CEO. Please proceed.

Thank you, and welcome to our call. Let me remind you we will be conducting it under Safe Harbor Provisions. Michael Duginski, our Chief Operating Officer and David Wolf, our Chief Financial Officer, are with me today and will make more detailed operational and financial comments after my opening remarks. Today, Berry Petroleum Company has posted its first quarter results for 2012. The company reported net income of $34 million for the quarter from oil and gas revenues of $234 million. Net earnings were affected by derivative and asset sales as well as changes in the mark-to-market value of other derivatives. Excluding these items, the adjusted net income was $50.3 million or $0.91 per share. Discretionary cash flow for the first quarter was $131 million. Cash from operations was $155 million. And the company generated an operating margin of $54 a barrel. Q1 production was 34,450 barrels per day, comprised of 25,100 barrels per day of crude oil and 56 million cubic feet per day of natural gas. Oil production was 570 barrels per day lower than the fourth quarter of last year, due to lingering curtailment in the Permian and a reduction in steam injection and active oil well completions in the diatomite, as we begin implementation of our redesign development there. Now let me make some more specific comments about the diatomite. As you well know, we announced in our third quarter call last year that we needed about 9 months to implement a number of operational changes in the field in response to requirements described in our project approval issued by the California Department of Oil and Gas. We have focused these changes on minimizing wellbore failures and their implementation is now underway. I would make 5 observations about the current status of the development. Number one, since the fourth quarter of 2011, we have drilled approximately 90 wells that we've discussed with you previously. With oil saturations, net pace and rock properties as expected. Second, steam injection into these wells has commenced. We are bringing on these new wells all at once in an effort to reduce the geomechanical stress on our wellbores. Implementation of this strategy did require us to take more wells off-line than we had previously forecasted for Q1, and this impacted production through the quarter. We have procured all the steam-generating equipment and permits that we need for our 2012 plan. Number three, operational. We managed the asset around active completions, and many of our wells have dual completions. With our recent drilling, we now have over 300 completions in our cyclic rotation with the new wells just receiving their first steam. We continue to anticipate the performance of our completions will be in the 18 to 20-barrel per day range. The fourth point is an important change that we're currently implementing and that is the reduction of the size of the steam injection cycles that we're reducing by about 50%. The concept here is to keep the total steam injection the same by increasing the cyclic frequency to offset the smaller injection volume per cycle. The use of these smaller injection cycles, while balancing total injection to withdraw, will limit the net dilation of the reservoir formation, and thereby, minimize wellbore stress. It's very early days here, but our initial data points are encouraging. And then number five, the regulatory environment in California continues to improve. We, of course, received revisions from the DOGGR removing the requirement to stop steaming wells within a 150-foot of a failed wellbore in the quarter. This requirement had been causing us significant problems through the end of March as we transition through this change. Furthermore, other the issues have continued to be resolved in April such that we believe the regulatory environment is not a limiting factor for Berry in California today. So overall, in the diatomite, we are implementing all the changes that we've been discussing with you. We have drilled the wells, we have our completions ready, we have our equipment and regulatory approvals. Now is the time for the steam to do its work. These changes have caused the diatomite to be about 400 barrels a day behind schedule for 2012. However, we still expect company-wide production to be in the 38,000 to 39,000 barrels a day for the year. I'll ask Michael to discuss the Permian, which experienced some curtailment in the first quarter; the Uinta, where we drilled some encouraging Wasatch-Green River vertical wells; and finally, our new steam floods. Before that, let me turn the floor over to David Wolf, who will provide additional details on our financial performance for the quarter. David?

Our first quarter of oil and gas revenues were $234 million. Oil revenues were $221 million. Gas revenues were $13 million. Total revenues including electricity sales, gas marketing, gain on the sale of assets and other items were $244 million. As Bob highlighted for the quarter, our adjusted net income was $50.3 million or $0.91 per diluted share. Discretionary cash flow was $146.1 million, which includes the gain on the sale of our natural gas hedges of $14.7 million. Excluding this item, our discretionary cash flow was $131.5 million. Our realized oil price per barrel average $94.23, average realized natural gas price was $3.52 per Mcf, gave us an average BOE sales price, including cash derivative settlements, of $74.44. Oil and gas operating costs were $17.31 per BOE, production taxes were $3.40, DD&A was $15.30 per BOE, G&A was $5.66 and interest was $6.41 per BOE. Total cost for the quarter average $48.08 per BOE, in line with guidance. If you compare these results with our 2012 guidance from our Form 10-K, operating costs were on the lower end of guidance due to decreased cost of fuel used to produce steam. Production taxes were higher due to increases in oil prices and higher assessments for ad valorem taxes. We have moved up our production tax guidance by $0.25 per BOE to reflect these items. G&A is higher in Q1, as usual, as we make certain compensation payments during this quarter. We continue to expect G&A to be within guidance for the year. Interest expense should remain relatively consistent throughout the year, a decrease in a per-BOE basis in line with our production. Our total interest, both capitalized and expensed, was slightly higher in the first quarter due to the timing of our $600 million of 3 -- 6 3/8% notes and the related tender and retirement of our 10 1/4% and 8 1/4% notes. Our operating margin was $50 -- $54 per BOE. Interestingly enough, if we are unhedged, our operating margin would be $54.50 per BOE, illustrative of very good hedges that we have currently on our books. At quarter end, our total debt was $1.4 billion. During the quarter, as I mentioned, we issued $600 million of senior notes due 2022 and used the proceeds to reduce the borrowing under our credit facility. In April, we retired $200 million of 8 1/4% senior subordinated notes and redeemed $150 million of our 10 1/4% senior notes. We also completed a credit facility redetermination, increasing our borrowing base to $1.4 billion with commitments unchanged at $1.2 billion. Our capital structure, adjusted for the refinancings, today is approximately $350 million funded under our revolver with about $800 million of liquidity, $205 million of remaining 2014 notes, $300 million of 2020 notes and $600 million of 2022 notes and a weighted average interest cost of about 6%. With that, I'll turn it over to Michael Duginski to walk through an operational review for the quarter.

Thank you, David. As Bob mentioned, first quarter production was 34,447 BOE a day, down 4% from Q4 in 2011. Diatomite production declined 300 barrels during the quarter due to reduced steam injection. Our Piceance in East Texas natural gas assets declined approximately 11% during the quarter with no capital investment, increasing our oil percentage to 73%. Production from our next-generation heavy oil projects increased 19% from Q4 to average 1,500 BOE a day. Production from both our Permian and Uinta assets were flat for the quarter. Bob has already covered the diatomite, but I would like to add a few additional comments. As discussed, we ultimately shut in more wells than forecasted to accommodate our drilling program. This resulted in Q1 steam injection levels 15% below Q4 levels. However, since the completion of the drilling program at the end of March, we are currently injecting steam at rates near last summer with the majority of the newly drilled wells receiving steam and ready to contribute to production. I would also point out that the requirement to abruptly halt steam injection from wells within 150 foot of a failed wellbore caused reservoir compaction, which had a more severe effect on these wells than previously anticipated. This actually increased the failure rate in the field and impacted Q1 performance. So the DOGGR revisions are critical to us going forward. Furthermore, the demonstrated performance of the diatomite assets provides us with a confidence that when we return steam injection to full set of completions currently available, we will resume the growth trajectory we saw last summer. As we mentioned, production from our next-generation heavy oil projects in California, which include McKittrick, averaged 1,500 BOE a day, a 19% increase from the fourth quarter. We began our drilling program at Main Camp and Pan and expect to drill approximately 40 wells on these properties during the remainder of the year. We still expect production from these projects to grow by 50% during 2012 and continue to look to accelerate the development of these projects as well as additional opportunities to add to our inventory of high-return projects in California. In the Permian, Q1 production averaged 5,600 BOE a day as we drilled 15 wells with an average of 3 to 4 operating drilling rigs. We plan to average 5 rigs during 2012, drilling 75 additional wells. We continue to be pleased with the well performance in this play with each of our positions performing on their respective type curves. The company made progress in the first quarter in reducing the gas plant curtailment issues that impacted production in the fourth quarter. We entered the quarter with 800 BOE a day of shut-in production. And while curtailments are considerably lower today, the effects of shutting in production and resuming operation resulted in production being flat. The company acquired an additional 16,000 prospective acres in the Permian, bringing our total Permian acreage to 58,000 net acres. We plan to drill 4 wells on the company's prospective acreage outside the Wolfberry fairway during 2012 and evaluate those results by year end. In the Uinta, production averaged 5,400 BOE a day. In Q1, the company drilled 15 Uinta wells, all of which targeted higher oil-potential areas. This phase of our drilling program is focused on testing the Wasatch where we completed 12 commingled Green River-Wasatch wells. These commingled wells continue to produce approximately 80% of oil. In our northern acreage, we have seen 30-day average IPs between 250 and 400 BOE a day and plan to add a fourth drilling rig during the summer. While the current drilling activity and total wells in the Wasatch has increased, we continue to test the Uteland Butte and are planning to drill 6 horizontal wells in 2012 and are focused on improving our completions during the year. While we have a contract in place to market our Uinta crude oil, we are in discussions with Holly and other parties to increase the volumes so we can deliver to meet our growth plans for our expanding developments in the Uinta. A few notes in closing before I turn it back to Bob. With the current fundamentals of crude oil in California and a high oil-to-gas price ratio, our margins in California are excellent, delivering approximately $80 per barrel in the first quarter of 2012. The 2012 diatomite drilling program is complete, and a majority of the newly drilled wells are receiving steam today and should begin to contribute to production in Q2. Permian gas curtailments are lower today, and we built a secondary outlet to lower further potential impact. We continue to be encouraged about the Uinta Basin and are focusing on higher oil areas that can improve our margin of these assets.

Thank you, Michael and David. We're available for questions.

[Operator Instructions] And your first question comes from the line of Brian Corales with Howard Weil.

Can you talk about where current production in the Permian is if a lot of those plants are -- the curtailments aren't there?

Yes, we are currently producing over 6,000 barrels a day and BOE a day, and we expect to continue to increase throughout the year.

Okay. And also, the additional acreage you added in the Permian, I'm assuming that's kind of up north. Is that a fair assumption?

Yes, most of new acreage is in Borden County. It's not in the Wolfberry fairway, but it's certainly in the Wolfcamp trend. We expect to exploit the Wolfcamp and maybe one other zone, one above or one below, probably.

And I'm guessing that's horizontally? Do you all plan to drill horizontal well up there this year?

We do have a couple of horizontal concepts we're testing. I think our first -- probably our first target is probably a commingled Wolfcamp/Strawn well. There is significant strong production in the area. But we have others. We believe there's Mississippian in there. We don't know if we want to do that horizontally or at a commingled fashion. Some people are touting the Cline Shale to be in that area and discussed plans that, that horizontal is in the Cline. So I think we'll start off commingled vertical and take it from there.

Okay. And then one last one, switching to the Uinta. Have you all drilled additional Uteland Butte well? And then between the Wasatch and the Uteland Butte, are you all seeing -- what are you all seeing, I guess it's better than you expected? And is there anything that's not as good as expected or may have changed your opinion from 3, 4 months ago?

Yes, we're seeing 2 different areas of the Wasatch that we're very encouraged with. The first is the northern area where we're seeing higher IPs in the 250 to 425 BOE a day range, and then we're seeing some southern wells on our acreage in Lake Canyon where we're in the 250 barrel a day -- BOE a day IP. So we're very encouraged by that and we want to continue to run a drill -- additional wells this year to get a better understanding of the overall play and the size of the play. We did drill an additional Uteland Butte well. We ran a significant amount of testing on that well. We ran a micro seismic on that completion. We completed it just recently in the second quarter and that well is currently cleaning up and coming on production right now. So we didn't talk a lot about the Uteland Butte, but we don't have a lot of new data today. But we're still optimistic that over the long term, we can develop a completion type that outperforms the Wasatch and the Green River commingled wells that we're drilling right now.

Brian, I would add, you've probably heard me say before, that at least on our part of the Uinta, it looks like there -- the Uteland will kind of divide into 2 groups -- Uteland wells will divide into 2 groups. One is a higher-rate well, but it has quite a bit higher GOR. So that well might be 60% oil, 40% gas. Then there's another lower energy Uteland Butte that might be more like 85% oil, 15% gas, but maybe 2/3 of the recovery of the higher GOR. So we want to do some more work to distinguish between those 2. And quite frankly, we're kind of enthused about the Wasatch results at the moment and that's probably going to be a more -- an area of more interest for us in 2012.

Your next question comes from the line of Joseph Allman with JPMorgan.

This is Jessica from Joe's team. I actually had a few questions on the diatomite. And I just want to be clear exactly what has changed since the year-end release and now that's bringing your diatomite production down? It seems like you have some wells that are off-line. Can you just explain that and elaborate that a bit more?

Sure. I think there were 2 events, which impacted diatomite. Number one, we did quite a bit of drilling in Q4 and Q1, 90 wells, as we said, and we decided to bring all those wells on at one time in an effort to reduce the stress off of these new wells. When we did that, that required us to reduce the steam injection in a number of wells in proximity to that drilling program because you can't be drilling -- you can't have live steam in proximity to active drilling operations. And it really caused us to take more wells off-line and reduce the injection more than we forecasted. The second impact that Michael alluded to was once we had to take wells off in 150-foot radius of the failed well, a well which failed its mechanical integrity test, and we had to stop steaming those wells within the radius, that caused an increase in the compaction within the 150-foot radius. And that caused a significant impact on those wells. Those wells today are at various stages of abandonment, repair, recompletion and redrilling and we'll be working on that group of wells throughout the balance of the year. So those are the 2 things that you find when you start to develop and reinitiate operations in a heavy oil project, you're going to have some of these events.

Okay. And just one last question on the diatomite. With the new DOGGR rules, you don't have to abandon wells within the 150-feet radius anymore, right? You don't have to that from now on?

We still have to get approval, but the approval instead of being 45-plus days, is probably now in the order of one day. So in effect, that approval has been pushed back down to the local office in Bakersfield. And we would say today that there's really no impact.

So it's similar to before, the old DOGGR wells were in place?

That is correct, that is correct.

Your next question comes from the line of Tim Rezvan with Sterne Agee.

Just had a couple of questions, you touched on them earlier. I guess I'll start in the Permian. Can you disclose kind of what that curtailment impact is today? You kind of quantified the 1Q effect, but we seem think there's still some curtailments. Can you quantify that?

Yes, there are still some curtailments. As they expand, the gas gathering system in the Permian it kind of comes and goes. We went -- we started out the quarter in the 800 BOE a day range and that ultimately went down near 0. But we've also seen some additional curtailments here in the second quarter, so we're not going to say that they've gone away, but we think that the impact is going to be greatly reduced with the new connections that we made so we made alternate connections to secondary outlets in our large group areas where we have consolidated operations. So we believe that the impact should be much lower.

Okay, that's helpful. And then just to push a little more on these 4 wells you're going to drill outside the Wolfberry. So you think you're going to start with one commingled. Have you -- are you going to wait on the results of the first one before you decide on the concepts for the other 3? Or do you know what you're going to do with those 4 wells already?

No, We've got 4 locations. We're going to drill the first one in Q1. We're going drill all 4. All 4 are going to be -- yes, I'm corrected, the 2 wells in Q2, I think all 4 will be commingled verticals. Now we're going to do some -- as you do in early days, of a appraisal program, we're going to some coring, we're going to do some more geologic work. If we fill the first well and we find we got a great Cline section, maybe we'll change the concept to a Cline horizontal. We don't have a prejudice or a predilection against not drilling horizontal wells. We just think that our geologic work today indicates commingle verticals as the way to start.

Okay. And then the final one, just on the Uinta discussions with HollyFrontier. We've kind of heard that there've been some discussions for quite some time. Can you kind of educate us on what that process might look like and what kind of might be a catalyst to get something done, renegotiated terms or an expansion of your agreement? And how can we think about that as far as timing and who controls the pace of that?

Well, the deal is not a deal until it's a deal. We have a contract, which is in place through June of 2013. This negotiation is no different than any other negotiation. It's all about value and term. And we'll just have to see where those negotiations go. We have a good relationship with Holly. We supply all of our crude to them today. So we'll just -- we'll see how quickly it gets done.

Your next question comes from the line of Neal Dingmann with SunTrust.

Just first question, as far as on the Perm -- on those wells you have commingled, what do you -- any idea what you think the cost will be on a well like that?

A Borden County well -- one of the reasons we went to Borden County is it was quite a bit more shallow, so maybe 8,000 feet as opposed to maybe 10,500 in the Wolfberry fairway. That's going to reduce your costs obviously well below $2 million. And obviously, it means the threshold for recovery can be quite a bit lower to generate the same return. We're actually interested in that and that was one of the reasons we picked this area. We'll see how they we perform.

Yes, and I heard the same thing. I agree with that. Just wondered on the Permian, what you're seeing now in general, just on differentials in the area?

We experienced that few-day blowout in differential due to some, I think, refinery maintenance. That seems to be resolved. I think, today, we're probably minus 3, minus 4 in the Permian.

And then just 2 other quick ones. On the Uteland moving over to Uinta, just wondered what kind of the depth or how much -- what are those run versus just the wells you've been drilling today over in the Uinta?

Yes, the depth on the Uteland is roughly around 6,000 feet, and we're seeing well cost in the $4.5 to $10 range.

Okay. And then just lastly, on the diatomite. It looks like there -- you mentioned all the wells that you'd drilled for the, I guess, fourth quarter and then first. What's kind of the plan as far as just typical number of wells now that you'll see for the remainder of the year there?

I think our program's finished on drilling, at least any drilling that would impact 2012. The real issue now is get the steam in the ground, see the response, measure how quick the response is going to be to the smaller injection cycles. We have quite a few completions to bring on and big increase in the total number of completions across the field, and that certainly should carry the performance for 2012. We'll have to make a decision quickly. We start to drill for next year. Whether we start to accelerate any of that drilling this year will not have impact on production. I think you'll see us, for the next few years, we should have drilling programs in the 100 to maybe 120 million -- not 120 million, 100- to 120-well package in the diatomite.

Okay. So it'd be more, I guess, evenly spread, so you probably won't see having the shut-ins that you saw in this last quarter or so?

That's the exact concept. I mean we're trying to -- so we think that the key to the diatomite is maximizing the number of wellbores that are active, or in other words, minimizing the amount of damage. And then the next key to keeping our production where we want it is to minimize the number of wells we have to take off-line to expand our operations. Obviously, as you put more wells into the rotation, you are bringing on a smaller percentage of new wells so that, that number of wells that you have off-line should go down over time.

Your next question comes from the line of Leo Mariani with RBC Capital Markets.

Just following up on the diatomite here, trying to get a sense of how many wells are still off-line that were producing prior to the new rules coming out by the DOGGR there?

Yes, I think what we try -- the way we really manage the field and plan the field is on number of active completions. And we really think that probably the most consistent way to talk about the field and its performance is to talk about it relative to the number of active completions that we have. We currently, with the new drilling program, with the wells that are still producing in our base and the wells that we're going to bring back and have brought that, we have over 300 completions, active and in the rotation. We have some upside to bring more completions on during the year. We have to see how that pans out. We also want to minimize the failures. Obviously, failures reduce the number of completions. We do think it's very important to point out that the number of completions that we have online this year is about 50% higher than the number of completions that we had in July of last year when production was 5,000 barrels a day. So it's about timing and it's about how responsive the new completions are going to be to the steam injection.

Okay. And I guess in terms of approvals, by the state DOGGR here of wellbore is that we're shutting -- I think on your last conference call, you mentioned you got a couple approvals. Can you kind of update us on that process? Have they approved everything? Are you sort of kind of halfway through your backlog? Any color you have there will be helpful.

Yes, the process is just -- it's night-and-day difference from where we were. Part of that reason was that we invested some money to develop some real time reservoir surveillance monitoring. We supply that data to the DOGGR when we asked to bring the well back online. It's taken both of us about 6 weeks to get that to work out, in other words, for them to understand the data we're supplying it and for us to give it in a way that really presents our case. So what you really have to do is you really have to show that the wells within the radius of failed way are not impacting the failed well. And now we have a way to do that. And those approvals as I said earlier, are about 1 day. So again, a number of those wells are in a different and various stages of coming back on. Some will not come back on, some will be re-completed because we can get one zone, if not 2 back. Until we have a number of those wells, all at various timeframes, at the end of the day, as I said earlier, we're going to talk about this now, going forward, a round number of active completions.

Okay. that's helpful. And I guess, just with respect to your production now on the diatomite, obviously, it was down a little bit on the first quarter. Where is that currently, and do you expect that to be up in the second quarter?

We do. We should be -- we have our steam injection back in the 45,000, 50,000-barrel a day range. We should see the base start to come back in Q2. We'll have to see how quickly we get well response on our new smaller injections. But at the end of the day, we still think we're going to get 18 barrels to 20 barrels per completion and we're going to have something on the order of 300 completions through the balance of the year. So that should give you some feel about where we think we're going to finish up.

Okay, that's definitely helpful. Jumping over to the Permian. I guess you guys just picked up a nice chunk of acreage, 15,000 net acres. Just wanted to get a sense of how much you all paid for that? And I guess, additionally, you talked about it not being in the Wolfberry fairway, may you could discuss sort of your geologic concept for targeting this particular area in more detail.

Sure. I mean we picked this up for -- I think it's in the Q. I think we picked this up for $500 an acre on an average or less. We had a -- our concept here was pretty simple. I mean there was a long-standing belief that Borden County had a lot of zones that we're going have high water saturation, so your production would be very water-prone. We went to the area, looked at it, we think we understand that, that is true in certain parts of Borden County. It's not true in other parts of Borden County. We could see some good Wolfcamp on existing legacy wells, we don't think there's been a hydraulic fracture, modern hydraulic frac job done in Borden County since the mid-'90s so we think there's some new technology to bring to the play. When we looked at the well cost, our view is if we could make the Wolfcamp plus one other zone successful, that would put enough barrels in the tank to get competitive returns. We see some areas where we think the Clear Fork is prospective. We certainly see areas where the Strawn is prospective. And, of course, there's been some Mississippian wells already drilled, not particularly in our part of Borden County, but there have been some horizontal Mississippians drilled, I think in the southwestern part of the County. Well, those are the concepts. It's really a way to establish an expanded footprint in the Permian Basin at low cost. And we're going to drill some appraisal wells and see how they work.

Your next question comes from the line of Matt Portillo with Tudor, Pickering, Holt.

Just a couple of quick questions for me. In terms of the 2012 CapEx, could you help us understand a little bit better how we should think about the trajectory going forward? I know that you're guiding around $600 million to $650 million for the year. And in Q1, it looks like you're around $167 million. So obviously, if you annualize it, it'll be a little bit higher. But there were some wells being drilled in the diatomite. I just wanted to get a little more clarification there.

Sure. The observation is correct. It's usually like that for us every year. We try to front-end load particularly our heavy oil projects because it takes a while for them to respond and if they are going to contribute, we have to do that as early as possible in the year. And you couple that with some carry-in that we had from finishing up some drilling in 2011, that's really the reason that the numbers skew that way. We're still -- we would still guide at the midpoint of the range at -- for the year at $625 million.

Okay. And then just 2 quick bookkeeping questions for me. In terms of the -- could you provide any guidance around the current production at Midway-Sunset kind of your legacy assets and how we should think about that for 2012? And then finally, just on the well cost side, if you have any update on your kind of dual completion in the Green River-Wasatch?

I think our South Midway asset produced about 12,400 barrels a day in the first quarter. We've drilled a few wells in and around those assets. And so normally, we think about that asset being on a 6% to 8% decline. We have had a couple of well locations that we've been able to find those assets and drill.

I think Q1, the legacy assets were about 12,800 barrels a day and those assets should experience another 5% decline over the balance of the year.

That's right. I looked at the wrong column on my sheet here.

And Matt, what was your question on the commingled Wasatch-Green River?

Just if you have any update on kind of where well cost are running at the moment for those?

Yes, we're in -- for the most part on average, we're in the $1.4 million range for the commingled both went to the base of the Wasatch.

Your next question comes from the line of Duane Grubert with Susquehanna Financial.

On the diatomite long term, it seems to me that we've had a lot of discussion of getting the immediate steaming back on and all those, but longer term, do you already start thinking about how do you manage subsidence? I guess my mental model is like your Midway-Sunset stuff, the wells get put in, they last for 50 years or 100 years. It sounds like this is going to be tougher to have diatomite wells last that long unless you put some -- something back into ground to get over subsidence. Can you talk me through that a little bit?

Well, we -- one of our big design criteria here, field-wide, Duane, is we try to balance the amount of fluid that we put in the ground with the amount of fluid that we take out of the ground. And we don't always do that because at some point, you have to be over injected to kind of get the compaction-dilation mechanism going. But overall, we don't want to have field-wide subsidence over the life of the field. Now, every diatomite developer usually plans to have about 15% to 20% well failures over the life of the field. And while that is alarming to some people, when you look at the percentage of the expense in the field, if you look capital to expense, expense is about 3x the capital in the field. And if you look at replacement drilling in total capital, it's a very small percentage because most of the spend is on facilities, pipelines and equipment. So we feel pretty confident that this field will have a long-term life. And it may not have the classic plateau to a long, long term, 6% decline, like a classic Belridge or South Midway, but we think we're going to be producing here for a long time.

And Duane, further to Bob's comments, since 2009, with all of the challenges that we've had, we've only deficit funded $25 million on this asset.

So it's going to be the foundational asset of the company as South Midway starts to produce out.

And kind of along the same lines, but from a happier perspective, gas prices are so darn low right now. Is there any way for you guys to lock that in for your steaming needs?

We're just starting to hedge Dubai on natural gas until gas prices would come up to a level where we want to invest in our own gas. We're starting to buy some 3-way caps, if you will, on the buy to try to protect our gas purchase and to lock in our oil-and-gas price ratio if you look at our oil hedge to our gas hedging position. We're just starting to layer that in. Look for us. They probably have some more significant numbers in Q2 on that.

Your next question comes from the line of Phil McPherson with Global Hunter Securities. Philip J. McPherson: Bob, I kind of jumped in and out, but on the 16,000 acres, is that all in Borden County or is there in other areas in the Permian?

No, no. I mean we are -- our real focus this year is to acquire some operational bolt-ons. You know that 648-acre lease that we're the natural owner of because we surrounded on 3 sides, that type of thing. So we're doing something of that. But just numerically on a pure acreage perspective, probably the preponderance of it is in Borden County. Philip J. McPherson: Okay, great I was wondering if you could help us on the rates that you gave us for the Permian production, the 5,600 barrels equivalent. How does that break down right now on an oil, liquids and gas basis? And could you do it also for the Uinta Basin?

Our performance in the Permian has been about 80% to 85% liquids-balanced natural gas. The reason that we selected some of the areas that we selected in the Permian was because they had a higher oil cut. We've tried to avoid some of the more southern acreage where you tend to be a maybe 40% crude oil and 25% NGLs on the balanced natural gas. So we kind of think of 85% liquids, 15% gas. Of the 85% liquids, 10%, 15% NGLs, 5 to 10 might be better. Historically, in the Uinta Basin, we've been about 60%, 65%. I think our actual average is 63% crude and the balance is natural gas. We do strip out a little bit of condensate and some NGLs. But overall, probably not enough to really make a difference. Philip J. McPherson: Okay, great. I appreciate that color. And in the Uinta, with the amount of wells that you drilled and production still being flat, what's the correlation there? Is it just timing of getting them on or are you getting bigger decline or something or...

It's mostly timing. The Uinta just delayed the decline curves or you probably need a little bit more than one rig active to keep production flat. And we typically, in the Uinta, run maybe one, maybe 2 rigs at most in the period where you have stipulations on drilling and then we almost always bring in one or 2 rigs in the summer months when we don't have the stipulations. So usually in the Uinta, because it's primary production, you see our bumps in Q2, Q3. Philip J. McPherson: The bump-ups you mean?

Production increases. Philip J. McPherson: Yes, okay, great. And given the kind of the weakness in the first quarter on production, I was kind of surprised on maintaining the guidance. So for second quarter, I know you won't get that granular, but are we going to see, I guess, a pretty meaningful increase in the second quarter or you think it's more third and fourth quarter? And in overall production?

Well, I think -- our focus here is to get response in the diatomite, hopefully get the base back on sooner, see the response on the smaller cycles, start to see that drilling impact in the Uinta in Q2. Also, if you noted, we really only ran 3 rigs in Q1 in the Permian. We are going to average 5 for the year. Obviously, that means we're going to have an increase in the number of wells that we'll be bringing on in the Permian. So it won't be linear. It'll be more in Q3 than Q2, but we would expect to have some increase in Q2. Philip J. McPherson: And do you care to even to, like you're around 16,800, or 17,000 barrels a day right now in California. To get to that 38, 39 number, I mean is 21,000 a realistic kind of goal to get in the fourth quarter, maybe an exit rate?

I hate the way to think about achieving the guidance is in the following parts. Our natural gas assets will decline 10% from the volumes you saw today. South Midway, our legacy assets, will decline 5%. From today, on a full year basis, diatomite will increase somewhere in the 30% to 35% range. The new steam floods will increase 20% to 30% in that average range, and Uinta in the 15% to 20% range. If you follow that math, you'll get to the midpoint of our guidance. Philip J. McPherson: And Permian?

Permian is in the 45% to 50% range in volumes. Philip J. McPherson: Okay, great. That's really helpful. Were you guys at all impacted in the quarter by the refinery outage in California? The Alon Refinery?

No, we don't sell to Alon. We sell -- we used to.

We've already seen that movie.

Your next question comes from the line of David Tameron with Wells Fargo.

Just following up, and I guess David just mentioned this, but you guys have thrown out this magical 5,000 barrels limit that everybody have become infatuated or fixated on. In the last quarter, you brought it down a little bit. Are you now thinking 4,000 for the full year average? Can you talk about -- I guess I can do the math from what David just gave us, but is that the right way to think about that?

It's 4,050. That's what's in our forecast for full year.

Okay. If I think about the Permian -- how much of your acreage you think is prospective for the Wolfberry? I know it's split but...

Well, I can say just about everything we have under development is obviously we bought it for the Wolfberry. It's proven to have the Wolfberry that's on a pure acreage basis. My guess is we're probably half and half maybe, 60% Wolfberry, but if our concept in Borden works out, somebody -- some clever person will have to come up with a new acronym, but it's going to perform just about like the Wolfberry.

Okay, that's helpful. And maybe -- I apologize if you mentioned this earlier. I was jumping back and forth, but did you talk about -- are you guys still looking for acreage out in the Permian or are you done leasing for now? What's the go-forward plan there?

No, I think we're still active. We're still looking. Said earlier, we're really trying to get some acreage in and around our producing areas that we really like and we're having some success there. And we still want to have some more prospectivity in the Basin. We like the Permian Basin. We like the margins. It's competitive as you -- obviously, everyone wants to be there. But yes, I think for us, today, that's a good place to expand.

Okay. And then final question. Can you -- I guess a couple years back, you were in front of, if you will, the LLS, the spread between Brent and WTI and the margins you're going to realize in California. Can you give us your current view of what your outlook is for oil prices as far as the spread goes? And what that looks like in your opinion over the next couple of quarters?

Well, I don't -- we're not any -- we don't have any more insight than anybody else. I think most people believe that when Seaway gets turned around, when Keystone's XL South gets built, you're going to see LLS to WTI go to a $5 difference. Most people have that forecasted sometime in '13. We think it's important to point out that a good part of that is because WTI is going to come up and if you look at that out month from the strip, that's exactly what's happened. I mean if you look 12 months out from the day, I think it's Brent to WTI is $5.50. We think that the heavy oil will continue to trade at some normal discount to Brent and will not be correlated to WTI. We are selling South Midway crude yesterday for about $114 per barrel as an example. So we're still trading this week at over $10 a barrel higher than WTI.

There are no questions at this time. I will now turn the call back over to Bob Heinemann for any closing remarks.

Thank you. Thanks for the participation in the call and the questions. We look forward to seeing you in the next quarter. Thank you.