Berry Petroleum Management Discusses Q3 2012 Results - Earnings Call Transcript

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Berry Petroleum (BRY) Q3 2012 Earnings Call November 1, 2012 12:00 PM ET

Executives

Robert F. Heinemann - Chief Executive Officer, President and Director

David D. Wolf - Chief Financial Officer and Executive Vice President

Michael Duginski - Chief Operating Officer, Executive Vice President and Assistant Secretary

Analysts

Brian M. Corales - Howard Weil Incorporated, Research Division

Andre Benjamin - Goldman Sachs Group Inc., Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Berry Petroleum Third Quarter Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Mr. Bob Heinemann, President and Chief Executive Officer. Sir, you may begin.

Robert F. Heinemann

Thank you, and welcome to our call. And let me begin by reminding you we'll conduct it under Safe Harbor. Michael Duginski, our COO; and David Wolf, our CFO, are with me today. They will make operational and financial comments after my opening remarks.

As we've been stating since 2010, our strategy at Berry is simply to focus our resources on growing production from our oil assets, and our third quarter results for 2012 reflect the implementation of this strategy. The company produced 27,500 barrels of oil per day, which represented 5% quarter-on-quarter growth in oil production, with solid increases from all 4 of our development assets. Diatomite led the way with an 18% increase over Q2. Our New Steam Floods grew 10%, our Permian production increased 6% and the Uinta delivered 5% growth.

Total production for the quarter was 36,300 BOE per day, up 3% sequentially, and this includes a 3% decline in natural gas production. Our mix was 76% oil and 24% gas for the quarter, and our overall operating margin was $47 a barrel. These results enabled the company to generate $125 million of discretionary cash flow, while net cash from operating activities totaled $144 million.

Our reported net income was $18 million, which included nonrecurring items of $21 million. Excluding these, adjusted net earnings for Q3 were $39 million or $0.71 per share. Oil and gas revenues were $233 million.

You may recall from our Q3 earnings call last year, we discussed the need to redesign our development plan for our Diatomite resource based on the performance of the reservoir, new regulations from California and the rate of regular well failures that we were likely to incur under those regulations. Today, I would like to provide you an update on our progress. Diatomite production for Q3 was 3,500 barrels of oil per day compared to 2,960 in Q2 and 2,700 in the first quarter this year. Our goal for the asset is to deliver reliable, steady growth for the company over the next several quarters. To accomplish this goal, we're focused on 3 things: first, reducing our well failures by using smaller steam injection volumes with more frequent cycling. Compared to the summer of 2011, we have cut our steam injection volumes into a Diatomite well by roughly a factor of 3 by doubling the frequency of cycling. As a result of this change, reservoir dilation or reservoir expansion is now about 60% lower than in July of 2011, and we have experienced no wellbore failures in our 2012 wells. It also appears this approach is generating the pressure and temperature in the reservoir needed for heavy oil production in the Diatomite.

Second, we're focused on developing the asset in a more continuous manner. We need to implement a more flexible development plan as motivated as to accelerate capital investment in our infrastructure so that we can develop any part of the field without project management constraints or delays. This acceleration has increased our 2012 capital, which is now expected to be approximately $675 million. We've also worked closely with our engineering and drilling partners to develop the ability to drill wells near areas that may contain active steam. We have begun testing this concept in October and are optimistic that this will eliminate the need to reduce injection in neighboring areas as we drill new wells or replacement wells.

Third, we're improving the reliability of our operations from increased reservoir surveillance and well testing. Our people have worked diligently to improve our real-time surveillance in the field. The objective here is to have the capability to monitor the zonal isolation of our steam injection to measure the productivity of all of our wells and to monitor their integrity.

Of course, when you're altering your development plan in real-time, you also discover concepts do not work. For example, during the third quarter, we tested the use of low temperature injection in a portion of the field. This caused an increase in the production of formation solids that resulted in a temporary processing outage and a decrease in oil production in September. We have since gone back to higher temperature steam, and production has rebounded nicely. We do not expect this event to be repeated.

Overall, we believe our redesign development plan will enhance the long-term net asset value of the Diatomite. The use of high-frequency cycling, continuous development and improved surveillance are also encouraging us to take an earlier look at the potential of infill drilling.

Before I turn the floor over to David Wolf, let me make some comments about 2013. Our strategy will continue to focus on growing oil production from our 3 existing basins. While we've not finalized our plans, looking forward to next year, our expectations are to increase oil production by 10% to 15% and total corporate production by 5% to 10% above 2012 levels. We will invest $500 million to $600 million of development capital, which can be funded from cash flow. We will direct 50% of the capital into California, 25% to the Permian and 25% to the Uinta. We should increase our oil percentage to about 80% of production enable us to generate a margin of just under $50 a barrel.

Inside the company, we talked to our teams and our people about our keys for success for next year, and we believe there are 4: first, minimize the base decline from our California legacy properties and utilize the growth from our New Steam Floods to make up the difference; second, continue to reduce our failures and increase our operational flexibility in the Diatomite to ensure its growth; third, increase the competitiveness of our Permian assets by improving our processing options and lowering our well cost; four, improving our margins in the Uinta by increasing our oil percentage in our production stream and increase our realized prices that we paid for our production.

With that, David.

David D. Wolf

Thanks, Bob. For the third quarter 2012, oil and gas revenues were $233 million. Oil revenues were $219 million. Gas revenues were $14 million. Total revenues, including electricity sales, gas marketing and other items were $245 million. As Bob highlighted for the quarter, our adjusted net earnings, $39 million or $0.71 per diluted share. Discretionary cash flow was $125 million. Our realized oil price per barrel averaged $89.04. Average realized natural gas price was $2.82 per Mcf, gives us an average BOE sales price, including cash derivative settlements of $71.45. Oil and gas operating costs for the third quarter were $21.20 per BOE. Production taxes were $2.91, DD&A was $17.64 per BOE, G&A was $5.32 and interest expense was $6.16 per BOE. Total cost for the quarter averaged $53.23 per BOE.

If you compare these results with our 2012 guidance for the quarter, operating costs were higher due to higher levels of work-over activity in the Permian and increased steam cost in Q3 versus Q2. The increase in steam cost was due to 26% increase in the price of natural gas used in steam generation. 50% of the increase of the operating cost are related to steam cost. Production taxes were lower, primarily due to decrease in the assessed ad valorem values of our Permian properties. Our operating margin for the quarter was approximately $47 per BOE. You derive this margin from the $71.45 average BOE sales price, which includes cash derivative settlements, plus our operating costs of $21.20 and production taxes of $2.91.

At the end of our quarter, our total debt was $1.6 billion, comprised of $1.1 billion of notes with staggered maturities in '14, 2020, 2022 and $510 million drawn under our senior secured credit facility. Today, our weighted average interest cost is about 6%, and we have approximately $650 million in liquidity.

With that, I'll turn it over to Michael Duginski to walk through an operational review of the quarter.

Michael Duginski

Thanks. As Bob mentioned, third quarter oil production was up 5% for Q2 to 27,500 barrels of oil per day, while our natural gas production declined approximately 3% during the quarter, increasing our oil percentage to 76% total production. Total production was 36,300 BOE a day, up 3% from Q2. In the Diatomite, production increased 18% from Q2, even though production was impacted by 500 barrels a day for the quarter from a facility disruption as a result of the production of reservoir solids.

We added new completions during the quarter as a result of repairing and drilling wells and have placed those completions in the active cyclic rotation. We are seeing the benefits of our new development plan and operating techniques. By using smaller steam cycles, we have improved the location of our steam in the reservoir, reduced the reservoir dilation, as well as the stress on the wellbores. We increased average steam injection to 58,000 barrels of steam per day for the quarter and are seeing production respond. We continue to increase our steam injection and expect to see an additional production increase in Q4. Based on the success of our 2012 program, we have accelerated our 2013 development plan by investing into infrastructure and prepurchasing equipment to allow for continuous development in 2013 and sequential quarterly growth.

In California, New Steam Floods production increased 10% to 1,900 BOE a day. In Q3, the company drilled 15 wells and increased steam injection. We expect to drill on additional 17 production wells before the end of the year. With the current differentials for crude oil in California and low gas prices, our margins in California were $71 per barrel in the third quarter.

In the Uinta, production increased 5%, driven by a 40% increase in Lake Canyon, while Brundage Canyon production remained flat. The company drilled 37 Uinta-commingled Green River-Wasatch wells, with 4 drilling rigs in Q3, and plan to drill 27 additional wells during the remainder of the year with 3 rigs. Our focus will continue to be raising our Uinta margins through drilling higher oil potential areas.

During the third quarter, the company acquired and leased a total of approximately 18,000 net acres in the basin. The majority of which is continuous with our Brundage Canyon acreage. For the year, we have increased our net acreage in the basin by 17%. We continue to deliver volumes under our existing marketing contract, which runs through July 1, 2013.

As we discussed before, part of our goal to increase Uinta margins is to realize higher sales price for our crude oil. The company is evaluating a portfolio of options, including contracts for Salt Lake City refiners, third-party marketers and rail. Our Utah refiner is currently in a scheduled turnaround, and we are building inventory in the field. We expect to work off this increased inventory by the end of the year.

In the Permian, Q3 production increased 6%, as we drilled 23 wells with 6 rigs. Infrastructure issues in the Permian, which affected Berry and others in the second quarter persisted, and were more impactful than expected. Basin-wide development activity is still at record levels, and for Berry, the following challenges affected our growth rate in the third quarter: the impact of high line pressures on production increased. We have installed gas compressors in Q4 to improve this situation; gas plant maintenance and upgrade-related disruptions increased to cause temporary production shut-in; and third, ethane rejection continues to impact production in Q3. Due to these issues in the Permian, we have scaled back our program, reducing our rig count from 6 to 4 in the fourth quarter, and we will drill 15 additional wells for the year. We plan to further decrease our rig count to 3 starting in 2013.

Before I turn it back to Bob, let me summarize our 2013 plan. We plan to grow our oil production 10% to 15% from a capital budget of $500 million to $600 million. We plan to accomplish this by minimizing our production decline in our base California assets, offset by increases in our New Steam Floods, delivering consistent sequential quarter-on-quarter growth in the Diatomite, by improving our Permian performance through better processing and lower well cost and finally, by improving our margins in the Uinta basin.

Robert F. Heinemann

Thank you, Michael and David. We are open to answering your questions.

Question-and-Answer Session

Operator

[Operator Instructions] I'm showing our first question comes from Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Just a question -- I mean, we heard, I guess, the Permian continues to kind of be a difficult place to operate, not being the kind of a 800-pound gorilla. In reducing the rig counts, what -- is there a means to an end? Or, I guess, is there something on the processing side, pipeline? Is there something that's going to happen over the next several quarters that may -- we may see this kind of lumpiness come to an end?

Robert F. Heinemann

Well, as we've said before, this issue is bigger than Berry, where I think it impacts us is in one of the areas that we think very highly of in northeastern Ector County. There's no surprise that so do a lot of other operators. There's a new plant that should -- is scheduled to open in April, and it should provide some relief. But we are also concerned that, that plant will fill up just about as quickly as all the other plants have in the basin. So we are poised to do more, if our processing solutions work. And if some of our alternative plans prove to be successful, then we can certainly start to go faster again in the Permian. But the way it stands right now, we thought it was prudent to slow down a little bit.

Brian M. Corales - Howard Weil Incorporated, Research Division

Right. And that -- I guess going down to 3 rigs, can that kind of keep production in the Permian relatively flat?

Robert F. Heinemann

That's correct.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then just to the Diatomite, you're continuing to see increases. How should we think about the Diatomite -- can you maybe say where you are today or about where you are? And then what can we expect from a Diatomite alone during 2013? I know timing's difficult but just trying to get a general idea or ballpark.

Robert F. Heinemann

I would say, today, we're cycling somewhere between 3,700 on the bottom and 4,500 on the top. Our goal is to continue to have quarterly growth, not unlike what we've delivered in the last quarter. That puts us somewhere next year in the low to mid 5s, something like that. We actually are encouraged by the Diatomite performance. We're encouraged by the progress our teams are making. We're really encouraged by having the wellbore failures from our 2012 drilling program. So we think we're getting our feet under us from the Diatomite and it's starting to show up.

Operator

Our next question comes from the line of Andre Benjamin with Goldman Sachs.

Andre Benjamin - Goldman Sachs Group Inc., Research Division

First, would Berry ever consider selling some non-core assets to maybe reduce leverage and free up capital like some of your peers in the Rockies have done? Are you seeing many opportunities to further increase your position in the key development plays? And how do you balance maybe quelling those positions with some bolt-on acreage versus reducing leverage?

David D. Wolf

Our strategy as it relates to the balance sheet is partly impacted by our strong hedge position in 2013. So as we look to '13 and the budget, we think we can keep our ratios flat to down, secured by, as I said, very good hedges that we have in place for over 50% of our production. Monetizing growth oil assets or gas assets that are depressed in terms of value related to the price doesn't really make sense for us at this time. And as it relates to looking at bolt-ons, we spent about $75 million this year through bolt-on, a $15 million bolt-on; and the Permian, an $8 million bolt-on, south of our Placerita field; and about $50 million in the Uinta basin. And so we think the balance sheet can support those small deals. So in 2013, we think we can continue the bolt-on strategy with those small-sized deals.

Andre Benjamin - Goldman Sachs Group Inc., Research Division

And then I guess on the cost side, you indicated half of the recent increase has been due to higher steam cost. How should we think about the other half in terms of the non-steam expenses going to next year?

David D. Wolf

The quarter -- additional quarter was associated to increase work-over activity in the Permian. There's another 15% that's associated with contract labor increases related to monitoring the Diatomite field. As it relates to next year's operating cost -- so a big proportion of this is associated with gas price. So you pick the gas price, we can hone in on the operating cost. We don't expect the level of work-over activity to be as lumpy in 2013 as it was this last quarter.

Operator

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

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just a couple of questions for me. In terms of the rig allocation in the Permian, could you talk a little bit about potentially testing some of the horizontal opportunities both within your core acreage for the Wolfcamp and then as you move into the Borden County acreage for some of the different opportunity sets that you're seeing there?

Robert F. Heinemann

Yes, what we're working on right now is we're doing 2 studies, engineering studies, one is -- that we're wrapping up is a 20-acre study for the entire basin where we have assets, and we should have -- that team should recommend opportunities here near the end of the year, something that we'll implement in 2013 on a test basis. As we finish that study, we'll focus in on 4 horizons for horizontal potential in the Midland Basin, the 3 sections of the Wolfcamp and the Cline Shale. In Borden County, we'll also be looking at the horizontal potential of the Mississippi. And once we get our test results back from the 4 appraisal wells that we're drilling, we may have a second potential zone in Borden County, which would be the Cline Shale. So we'll be doing that engineering work next year, and we'll -- you'll see us come out and start doing some testing potentially in the back half of '13 or beginning of 2014.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And just to clarify there, the -- is that a combination of testing for horizontal drilling, plus the down-spacing opportunity? Or would you potentially test the down-spacing opportunity before then?

Robert F. Heinemann

I think that the down-spacing will be first, and as we get those results, we'll continue to gather data on the additional shale opportunities. And then you'll see the horizontal potential tested later on in 2013.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And then just a question -- 2 quick questions on the Uinta. Could you give us an idea of maybe where you're looking at kind of rig count activity for 2013? And then as you mentioned, the inventory build into Q4, could you give us an idea of maybe where you're expecting to see sales on a volume basis for the fourth quarter in the Uinta?

Robert F. Heinemann

I think rig activity varies over the course of the year, depending on winter stipulations. Part of the year, we'll run 3, part of the year, we'll run 2, and for a small time, we might even go down to 1. So it kind of moves up and down as it usually does over the course of the Uinta. Additional inventory issue for us in the fourth quarter is going to be, can we get all those inventory volumes sold and processed? There is some likelihood that we don't get it all worked off, and if we don't, that will spill over into Q1 next year into sales. Numbers, kind of uncertain to predict at this point. Refiners started to increase the number of loads that he's picking up and processing, but of course, he's got to go through his restart up as well. And that may impact us for a couple of weeks yet.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And could you remind us which refiner that is?

Robert F. Heinemann

It's Holly's Woods Cross refinery in Salt Lake City.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, perfect. And then just 1 last quick question for me. As we think about your gas production in 2013, could you give us an idea of kind of how you're thinking about base level declines there?

Robert F. Heinemann

Probably 20%, 25% decline in our gas assets. That's somewhat offset by associated gas coming from the Permian and the Uinta. We are just -- between our production and some hedges that we've purchased on gas, we remain very insensitive to gas overall from a cash flow perspective.

Operator

And our next question comes from the line of Duane Grubert with Susquehanna Capital.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Yes, Bob, with the way the shares are trading, can you talk to us about your philosophy of how you might think about encouraging share buybacks at some level?

Robert F. Heinemann

Well, David, you want to...

David D. Wolf

Yes, I think where the balance sheet stands today with our debt-to-EBITDA in the high 2s, I think that would prohibit us from buying back meaningful shares at this point. We do think as we look forward to the development, the Diatomite, that we're optimistic that a lot of the issues are behind us. So as we look forward to 2013, we expect to be able to deliver on the growth that Bob had highlighted, and the share price will take care of itself.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Okay. And then, obviously, you are insensitive to gas prices, as you mentioned. But I'm curious, in California, have you ever had a philosophy of locking in gas prices there at all?

Robert F. Heinemann

We have started to hedge some in that way. We really buy caps on natural gas. We bought -- purchased about $10 million, I think, for next year as our gas -- if we're still going to be on a $3.50, $4 gas world, I think we continue with that strategy and let production decline from our assets and then use hedges to protect us from the upside exposure.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

A bit more operational question. The solids that you had trouble with in your equipment in the Diatomite, was that reservoir material or a sludge? Or what is the nature of the solid?

Robert F. Heinemann

When you produce Diatomite, you always -- it's very incompetent, as you all know, and then it always comes back to you. What we were really trying to do was we were trying to test on lower temperature injection because we thought that, that will even further improve our wellbore situation. Of course, to get the same amount of heat in the ground at lower temperature, you have to inject a lot more fluids. And then when those wells start to come back to us on flowback, our processing system that normally handles those solids is really overwhelmed and was really shut down for about a 7-day period of time. And, of course, we had to go in and clean out the wash tank, et cetera, et cetera. So we've not seen enough upside from low temperature to embrace that technique. So we went back to high temperature injection. Production came right back to where it was. And so we really don't expect it to happen again. We are making some process modifications as a backup so that we're not impacted going forward.

Operator

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

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

So just a couple of questions. First, I was just wondering around your production growth. I'm wondering now that you're adding the steam on the Diatomite and cutting back on the Permian. Do you see, I guess, going forward, maybe production being a little less volatile or less prone to some of the hits that you've had this year after doing those 2 things?

Robert F. Heinemann

Absolutely. That's probably design criteria #1 for our program next year. And as we think that the redesign plan in the Diatomite is starting to straight that stability, we see that more stable quarter-on-quarter growth that we're used to coming back to the story.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just wondering, I understand, I guess, why you're cutting back in the Permian. I guess was that just not foreseen, I guess, early in the year, I mean, when you're relatively tight? Why use the cash to do a bolt-on in the Permian if you're ultimately going to cut back on production this year?

Robert F. Heinemann

Well, that was early in the year. It was also in one of the higher EUR areas that we had in the portfolio, and it helped maintain the drilling inventory going forward. Those are really the drivers. We still like that acquisition. It's worked out fine for us. It's delivered the value we thought it would deliver.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. No, that makes a lot of sense. And then just lastly on the Diatomite. You mentioned about pushing the steam and to see some incremental production there. I mean, just wondering in more broad terms, how much more can you push that? Or how much -- what type of incremental production increase could we potentially see out of that, I guess, into next year?

Michael Duginski

Well, we -- our steam injection is limited by our -- the number of steam generators we have on the ground, and we're maxing that out right now. We're matching our steam injection to our -- the number of completions that we have, and we have increased both of those. And as Bob had highlighted, we expect to continue this type of growth quarter-on-quarter, and I think it's in the 500- to 600-barrel-a-day per quarter. And that ends up being in the -- we should be in the low to mid 5s as an average next year, but we'll obviously bring on the maximum amount of steam that we can and optimize that production the best that we can.

Robert F. Heinemann

The other thing we've emphasized today is we pre-invested to give ourselves more flexibility. And as these completions prove out as we get more generators, this does give us the ability to accelerate the field or maybe better said, it will enable us to operate the field, like we operate just about everything else in California. So it gives us some stability along with the capability to go faster upon success, and we think that was more than made up for the amount of incremental capital that we brought forward in '12.

Operator

Our next question comes from the line of Jason Wangler with Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Curious on the Permian with the 3 rigs. I know you talked about that you're going to kind of give us maybe a little bit more info on the newer acreage, if you will, later this year or even early next year. But do you have an idea so far of the 3 rigs that are just going to kind of stay in the core areas? Or will you still be kind of going out and testing new series [ph] out there as well?

Robert F. Heinemann

We're going to focus on our best areas in Midland Basin, and that's really how we chose the 3-rig program. We'll be focused in our northern Ector County properties, and you will see us follow up on those appraisal wells we drilled next year as substitution. We'll bring a rig up there if based on the results to continue to expand the appraisal of that acreage.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Okay. And just up to the Uinta, are you looking at any other formations now? Or will we see anything maybe next year? Or are you pretty happy just with the vertical co-mingling program now?

Robert F. Heinemann

Well, we are pleased with the annual Wasatch-Green River, and it looks to be prospective, quite a bit further to the South than we originally had forecast. So it's adding to some of our wells in the Ashley Forest. We still have the concept of drilling horizontal wells in the Uteland Butte, but we believe we need longer laterals to be successful to do that. We're starting to work on those approvals, but quite frankly, our program for next year in Uinta does not require that to be successful. We have a large inventory now in the Uinta. We've added about 350 to 400 locations with our EIS in the Forest and our bolt-on acquisition, which is acreage, which is really located primarily between Lake Canyon and Brundage Canyon. So we have a much larger, more prospective inventory in Uinta.

Operator

[Operator Instructions] Our next question comes from the line of Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

A question on the Uinta. You talked about 3 things you were looking at, one of which was a rail solution to get barrels out of your basin to improve your pricing. Can you kind of walk us through sort of how that works? I know your crude is pretty waxy in the Uinta, and there's a limited number of refineries that can take that. I guess with that involved, potentially trying to get refineries to kind of retrofit themselves to take your crude or are there other spots that can already sort of take it today? Can you just kind of provide some color on that?

Robert F. Heinemann

Sure. The crude in the basin is waxy, but that does not mean it's not an attractive crude. Some of the nice things about the Uinta crude is it probably has the lowest sulfur content of any crude in the U.S. It's light, it's a 42-degree gravity and it's actually fairly easy to crack. It's good for the processing and refineries that are emphasized middle distillates and anode-grade coke. So there are some very positive attributes. And, of course, the amount of volumes that I think would be exported to the basin are not enough that would dominate the slate of any refinery. So it's a matter of finding the right blending. We actually think that the crude can find more than one home outside of the Salt Lake City market.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right, that's helpful. And I guess jumping over to Diatomite real quick, I know you guys previously had talked about being at 5,000 barrels a day at the end of 2012. Now you guys are saying kind of low to mid 5s next year. I just wanted to get some color around kind of why it's just a little bit behind here in the last couple of quarters, if there's any reasons you can kind of point to as to why the production has lagged a little bit.

Michael Duginski

Well, what I would tell you is that when you look at what our production plan was for the Diatomite, we're probably -- when you look across the year, we're probably about 4 weeks behind schedule. And when you're trying to predict the ramping of heavy oil, obviously, that can be a difficult task. And we're just slightly behind schedule. The other thing I would tell you is this subset that we had in September set us back slightly. As Bob said, it was about a 7-day occurrence, took us about 1.5 weeks to get production back up to the levels that it was at and we don't expect that going forward.

Robert F. Heinemann

And also, when you compare the ratios, we're kind of talking midpoint of next year to midpoint of this year when we talk about the growth rate. So Diatomite's going to continue to ramp up pretty nicely next year.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess do you guys have kind of a longer-term target in mind for where that production can go?

Robert F. Heinemann

Yes, we're still confident, 15,000 barrels a day. We still feel good about 23% recovery factor. We think the smaller cycles -- when you use these smaller cycles, you have less stimulation density around the well, and we think that encourages us to look at infill drilling earlier than we probably would have otherwise. So we think that, that -- the smaller cycle and higher frequency cycling can create some real value in the asset.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Got you. Okay. And in terms of CapEx in 2013, you guys talked about ramping down the Permian. It sounds like Uinta is kind of continuing along a steady state. In terms of California spending, is that expected to also come down at all in '13 or is that going to be more flat with '12?

Robert F. Heinemann

California is up, Uinta is actually up, Permian offsets it. We're spending about, again, 50% of the capital in California.

Operator

And our next question comes from the line of Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Can you give me a sense of how much gas you're consuming currently relative to your production? And so it sounds like in '13, you likely will be consuming more than production. Is that right? And you're looking at hedging?

Robert F. Heinemann

I think we're consuming about 60 million a day right now, something on that order, and we produce upper 40s to 50 million a day. So that 10 million shortfall has been hedged for next year. So we're pretty covered.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. So you'll just sort of cover the difference through hedges, sounds like it on a go-forward basis, at least in the near term.

Robert F. Heinemann

That's correct.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then in the Diatomite, can you just quantify just the shorter cycle time, what it used to be, what it is now? And then as well, maybe just give us a little color in terms of the lower pressure? Does it have an improvement on your steam oil ratio or your productivity per well or anything like that?

Robert F. Heinemann

So if you went back to summer of '11, our base cycling practice was to inject 2,000 barrels a day for 3 days, let that steam soak or transfer its heat, what we call the soak period for 1 to 2 days, and then flow that well back for about 15 to 18 days. Now, what we're doing is we're injecting 2,000 barrels a day for 1 day. We have eliminated the soak to simplify our operations, and we produced back for about 9 days. So when you look at that and you just kind of play that out on a calendar, we are really -- have reduced our injection per well at any point in time by a factor of 3, but we've offset that by doubling the cycling. And indications are, we measure our well performance, that, that's giving us enough pressure, enough temperature at a lower expansion to give us the well performance or the completion performance that we need.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

So the well performance or productivity per well, is it still the 20 barrels a day?

Robert F. Heinemann

19, 20 is kind of our type curve. It depends on the area. We have different areas that produce above it, some areas that produce below it. We have some areas that are well up the type curve, some areas that are just moving up the curve as we restart. But that's where we designed it to be at the peak of a well.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And so I'm taking it this is improving your steam oil ratios, too, then, isn't it? The lower pressure and the shorter injection cycles?

Robert F. Heinemann

Well, I think that's probably to be determined as we go up the development cycle. When we're bringing on a lot of new completions that have very high SORs, it's hard to make that -- it's hard to make the argument that the SOR's coming down. But perhaps that's probably something we need to look at in our long-term modeling of the asset or what happens to SOR at the plateau.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then just a final question. I know you haven't given detailed guidance with '13, but in terms of on the oil side, if we're thinking about South Midway, should we think about a 5% decline Permian flat and then offset by the Diatomite growth -- or I mean Diatomite growth allowing corporate production, oil production to be grown, based on the guidance you gave?

Robert F. Heinemann

Well, we have several moving pieces. So we have Permian flat, we do have a decline in our South Midway asset team. I don't know that rate right in front of me, but 5%'s probably not that bad. And then we have Uinta growth, Diatomite growth and New Steam Flood growth, and that's how those pieces fit together. Actually, I should say Permian is not exactly flat year-on-year. There is a growth component in the Permian as well. It's just not as large as the other assets.

Operator

And I'm not showing any further questions at this time. I'd like to turn the call back over to Mr. Bob Heinemann for closing remarks.

Robert F. Heinemann

Thank you for listening in on our call and our results. We look forward to seeing you in the next quarter. Thank you.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a wonderful day.

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