California Resources Corp (CRC) 2015 Q1 法說會逐字稿

Good day, and welcome to the California Resources Corporation first quarter 2015 earnings conference call. All participants will be in listen-only mode. (Operator instructions.) Please note this event is being recorded.

I would now like to turn the conference call over to Mr. Scott Espenshade, Vice President, Investor Relations. Mr. Espenshade, the floor is yours, sir.

Thank you. I'm Scott Espenshade, Vice President of Investor Relations. Welcome to California Resources Corporation's first quarter 2015 conference call.

Participating on today's call is Todd Stevens, President and Chief Executive Officer of CRC, and Mark Smith, Senior Executive Vice President and Chief Financial Officer, and also several members of the CRC's executive team.

As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ from those expressed or implied in these statements.

Additional information on factors that could cause results to differ is available in the company's 10-K. We would ask that you review it and the cautionary statement in our earnings release.

Our first quarter 2015 earnings press release and accompanying slides for the conference call have been posted on CRC's Investor Relations page, which can be found at www.crc.com. We have allocated ample time for Q&A at the end of the call, and would ask that participants limit their questions to a primary question and a follow up.

I will now turn the call over to Todd.

Thank you, Scott, and thank you, everyone, for attending our earnings call.

We completed our first full quarter as an independent company, and are strongly encouraged by our results even with the challenging commodity market. As we entered into the downturn, we laid out our 2015 priorities for the business, and our focus quickly turned to the balance sheet.

We had to live within our means and bring our capital investments in line with projected cash flow. Our second priority was to seek an amendment from our banks to provide us time to work through this period of lowered prices. Lastly, we had to right size our costs for the current operating environment.

So, how did we do? Following the spinoff, we responded to this rapid price decline by swiftly reducing the capital for the remainder of 2014 and cut our 2015 capital investment program to $440 million, a reduction of about 80% compared to 2014.

We brought our drilling rig count from 27 in November down to three rigs that we are currently operating. We invested $133 million for the quarter, which was below our guidance. We worked with our lender groups to deliver on our credit amendment that provides flexibility through the end of 2016 to implement our deleveraging plan.

Lastly, we also delivered record crude oil and total production as well as cost reductions for the quarter, and we are in detailed discussions with various parties regarding the full suite of deleveraging options available in our broad portfolio.

So, again, not the market I would have chosen for our first full quarter. But, given the hand we were dealt, we could not have been prouder of CRC's execution.

What differentiates CRC from our peers is that we manage a technically and operationally diverse world-class resource base with substantial operational and financial flexibility. In addition, our management and operating teams have extensive experience in all phases of the commodity cycle.

We have been tested in our first few months as a public company by the rapidly declining oil prices. We are confident that our diverse resource base and our dedicated and highly motivated workforce will allow us to meet the challenges brought about by this price environment.

Many have heard me stress protecting our base production and focus on cash margins, which I have emphasized to our workforce. These are important because, by protecting our base, we'll be in a strong position to ramp up our activity level by increasing our already deep inventory and maintaining our margins.

We achieved record quarterly crude oil and total production from our 2014 and 2015 capital programs with their emphasis on lower decline projects. We expect the emphasis on our base production to become more evident as the year progresses.

Our focus on cash margins also continues to show progress. We are controlling operating costs and achieving capital efficiencies while maintaining our attention to safety and proactive community outreach efforts.

While we delivered on all aspects of our operations that we control, we dealt with significant commodity price related headwinds during that quarter that impacted our financial results. Mark Smith, our CFO, will discuss our financial results in detail shortly.

As I have stated before, we are committed to living within our cash flows. Our asset base provides us the operating flexibility to adjust our capital program rapidly during the course of the year based on market conditions, as well as the ability to shift our capital between basins and drive mechanisms to optimize returns throughout the commodity cycle.

As I will discuss later, we are also making progress in our efforts to de-lever our balance sheet. Our 2015 capital program is entirely focused on higher margin, higher return, and low decline crude oil projects.

Beginning in 2014 and continuing to 2015, we are shifting our emphasis to steam and waterflood projects that offer a lower decline and risk profile while providing attractive returns over their economic lives. The investments that we made in 2014 in steam and waterflood projects are delivering a positive impact on 2015 production.

A result of this shift, we believe, that in 2015 our overall base production decline will be lower than historical rates. And we also expect Elk Hills' decline to continue to moderate as Elk Hills' production profile continues its shift from primary to secondary drive mechanisms.

We have implemented our Value Creation Index, or VCI, metric across all levels of the organization, and have received complete buy-in and appreciation of the transparency on how the company is allocating capital.

Our simple formula of the PV-10 of the pre-tax cash flows over the present value of the investments over the project's life allows everyone to know and understand the criteria for investment.

Our first quarter production was ahead of our expectations and the guidance we provided. This was primarily the result of a lower decline in our base production and the production sharing effects in our Wilmington Field operations.

The main contributors to our production success include our ongoing shift towards lower decline projects that can create sustained long term value, as well as our focus on optimizing base production. Our personnel across all our operations have contributed to efficiency improvements that are sustaining our base and lowering both operating and capital cost.

We expect to increase our 2015 average daily crude oil production above our 2014 level while keeping average production on a BOE basis essentially flat compared to 2014. Looking ahead to the second quarter, we expect our oil production to be consistent with our record first quarter level, while our production on a BOE basis is expected to decline modestly to a range of between 158,000 to 163,000 BOE per day.

As I have mentioned before, our base capital requirement has come down as a result of the shift in our capital allocation. We believe this will enable us to keep our total production for the remainder of 2015 nearly flat, with a slight gradual decline as the year progresses.

If the current price environment persists into 2016, we would expect to continue to stay within our cash flows, as we had indicated before. Our objective would be to maintain our oil production essentially flat while our total production experiences modest declines.

We have a significant amount of project inventory and flexibility in how we accomplish our goals through our capital allocation process based on the VCI metric.

During the first quarter, we also saw the positive impact of our quick and decisive steps to curtail cash outflows resulting from our cost containment efforts. Production costs in the quarter were $16.20 per barrel, which were comparable to the $16.07 per barrel in the fourth quarter of 2014 and notably lower than the prior year's first quarter cost of $18.43 per barrel.

Our production costs per unit have generally been declining for the past year. We've started seeing the benefits of our efforts at all levels of our organization to implement more efficient methods, to streamline our processes, and to work with our suppliers.

The decline in our operating costs results in part from lower natural gas prices, which significantly lowered the cost of steam generation for our steamfloods as well as the cost of electricity for our field operations. Electricity prices also tend to be lower in California in the fourth and first quarters due to seasonal factors.

While we expect modest pressure on our operating costs in the second quarter from higher electricity prices as we enter the high season, we expect to offset some of this price pressure by further improvements in the controllable components of our operating cost structure.

In addition to the low price environment that persisted throughout the first quarter, we experienced several discrete events in California, including the effects of the nationwide refinery strike and a fire at a local refinery. We were able to market our effective production during the quarter. These events contributed to widening of differentials in California, further pressuring our realized prices.

The strike has recently ended. While we believe the effects of these events will take a few more months to work through the system, we believe our realizations should begin to improve gradually during the year.

We will continue to be strategic and opportunistic with our hedging program in support of our capital investment plans. We have been reviewing our hedging options for late 2015 and into 2016 based on our expectations of the price environment.

So far we have placed hedges on almost all of our oil production for the first half of 2015, about two-thirds of the oil production in the third quarter, and about one-third of the oil production in the fourth quarter of this year.

The hedges have been focused mainly on protecting our capital program against further price deterioration. Over time, we envision establishing a 12 to 18 month hedging program in a normalized pricing environment.

I'd like to point out also that our low natural gas prices gives us a natural hedge, as a significant portion of our operating costs are tied to the price of natural gas, which is used for steamfloods as well as power.

As a California company, CRC and our workforce are committed to doing our part to alleviate the effects of the state's drought. Through our longstanding investments in water conservation, we already recycle approximately 79% of our produced water in our improved and enhanced oil recovery operations.

In 2014, our operations also provided more than two billion gallons of water to local water districts and farms. As a result, we are a net water supplier to agriculture, providing more water for irrigation than the amount of fresh water we purchase for our statewide operations.

We and other operators are working to further reduce our freshwater use and are committed to expanding our role as a net water supplier. We do not currently expect the state's announced water restrictions to impact our level of oil and gas production.

We ended the first quarter with a debt balance of $6.6 billion as a result of the distribution made to our former parent at the spinoff. We expect to exit 2015, excluding the results of potential deleveraging initiatives, with a debt level comparable to the end of the first quarter.

And in February, we negotiated an amendment to our credit agreement through the end of 2016. The amendment modified certain covenants to take into account the weakness in the price environment.

While we believe the modified terms of our credit agreement will enable us to work through the current commodity price cycle, we have been exploring various alternatives to de-lever our balance sheet and to better align our capital structure for a more modest and normalized commodity price environment.

The deleveraging options we are exploring reflect the flexibility of our resource base, and may include a combination of asset monetizations, joint ventures, and other opportunities. Given the long time horizon and growth potential of our asset base, we are conducting a thoughtful assessment of the various midstream and upstream alternatives to enhance shareholder value not only in the near term, but for the longer term.

We are progressing with these deleveraging efforts and are actively engaged with various parties, focusing on potential structures, transaction costs, and implications for our portfolio. We expect to make significant progress on these activities and hope to enter into one or more transactions by the end of this year.

In addition, should prices improve significantly in the latter half of the year, we would apply the majority of the incremental cash flow to towards debt reduction.

I will now turn the call over to Mark to discuss the details of our first quarter results.

Thanks, Todd. Our first quarter results largely reflect two factors; first, our record levels of production, second, continued low energy prices.

Our cost control measures helped soften the impact of low commodity prices. These measures included our reduced capital investments, as well as our actions to reduce our production cost. Our operations teams has been excellent in protecting our base production while making the adjustments necessary to live with our projected cash flow.

Let me summarize and comment on our results. Notably, our levels of production beat our expectations and guidance for the first quarter. Our average oil production hit a record of 108,000 barrels per day. That was 14% higher than last year's first quarter and 3% higher sequentially than the fourth quarter of 2014.

Our operations in the San Joaquin Basin delivered a year-over-year increase in oil production of 5,000 barrels per day, reflecting our focus on steamfloods. Production for our other assets increased by 8,000 barrels per day, which included the effect of lower prices on our Wilmington Field production sharing contracts.

NGL production declined slightly from year ago levels. And natural gas production remained unchanged after a slightly increase in 2014, when our capital investment program was much larger.

Total oil and natural gas production averaged a record 166,000 barrels of oil equivalent per day. This record production represents an increase of 12,000 BOE per day, or 8% compared with the first quarter of 2014. Sequentially, total production in the first quarter of 2015 increased by 1,000 BOE per day compared to the fourth quarter of 2014.

More than offsetting the positive effect of increased production was the continued decline in prices for all of our products. Most of those declines followed the weakness in Brent, which was down 49% year-over-year and 28% sequentially. In addition, our realized prices were driven below historical differentials to Brent, in part by the refinery events that Todd mentioned.

As a result, our realized crude oil prices averaged $46.44 per barrel in the first quarter. This compares with realized crude prices of $102.32 in last year's first quarter, a decline of 55%. In the fourth quarter we realized $68.54, resulting in a decline of 32% sequentially.

Largely as a result of the refining events, NGL realized prices decreased even more than crude prices in the first quarter, falling to $21.55 per barrel, down from $60.39 per barrel in last year's first quarter, a 64% drop; and from $34.41 cents per barrel in the fourth quarter of 2014, a sequential decline of 37%.

Realized natural gas prices also decreased $1.94 per McF, or 41% below last year's first quarter price of $4.78 per McF, and 29% below the $4.00 per McF prices we realized in the fourth quarter of last year.

Reflecting the positive effects of our cost containment program, our production costs for the first quarter of 2015 were $242 million, or $16.20 per BOE. This reflected a 12% decline from $18.43 per BOE during the prior year period.

First quarter 2015 production costs were lower than fourth quarter 2014 costs of $243 million and relatively flat on a per unit basis. Lower first quarter costs reflected improved well servicing efficiency and lower costs for gas used to generate steam and power, consistent with Todd's comment that gas acts as a natural hedge for us.

Taxes other than on income were $55 million in the first quarter of 2015 compared with $52 million in last year's first quarter and $54 million in the fourth quarter of 2014. These consist largely of property taxes, which are regularly reassessed at midyear, and the cost of greenhouse gas allowances and production taxes.

Reflecting our significantly reduced drilling activity, exploration expense was $17 million in the first quarter of 2015, compared with $31 million in the first quarter of 2014 and $68 million in the fourth quarter of 2014.

Interest expense during the first quarter was $79 million due to the debt we incurred in connection with the spinoff in the fourth quarter of 2014. Additionally, our overall effective tax rate in the first quarter was 41%.

As a result of these factors, we ended the first quarter of 2015 with an adjusted net loss of $97 million, or $0.25 per diluted share. This compares with adjusted net income of $223 million, or $0.57 per diluted share, for last year's first quarter, and an adjusted net loss of $7 million, or $0.02 per diluted share, for the fourth quarter of 2014.

Our net loss was $100 million, or $0.26 per diluted share. This compares with net income for last year's first quarter of $223 million, or $0.57 per diluted share.

For the fourth quarter of 2014, we had a net loss of $2.1 billion, or $5.47 per diluted share. You'll recall that the fourth quarter included a $2 billion after-tax non-cash property impairment charge to the carrying value of certain of our properties due to low commodity prices.

Current quarter adjusted EBITDAX was $198 million. This was down from $705 million in last year's first quarter and $454 million in the fourth quarter of 2014.

As we described in our last earnings call, we responded aggressively and deliberately to falling commodity prices with decisive measures to adjust our capital investments, largely by reducing our rig count.

Our capital investment for the current quarter was $133 million compared with $475 million in last year's first quarter and $520 million in the fourth quarter of 2014. Said differently, we were running 27 drilling rigs in November of 2014. We were down to six rigs at year-end. In the first quarter, we were running only three rigs.

I want to point out that our reduced capital investment of $133 million was relatively in line with our operating cash flow for the first quarter. This excludes approximately $200 million of cash outlays from capital investment projects that we completed in the forth quarter, as well as our year-end exit rate of spending, which I discussed in our last earnings call. We expect a modest amount of this effect to continue into the second quarter.

In the last conference call, I spoke to the fact that we were well advanced in our discussions with our banks relative to the credit amendment. Shortly thereafter, we executed the final agreement.

I'd like to note that I'm very proud of the strong support CRC received from our bank group and how we were able to work together to craft an effective credit amendment. This agreement's a testament to CRC's large and diverse resource base as well as our prompt response to the price environment.

We're approaching our deleveraging efforts in a consistent fashion, with thoughtful consideration of how to de-lever the balance sheet while still maximizing the net asset value of our overall portfolio.

In closing, for the quarter you've witnessed firsthand CRC's commitment to live within our cash flow and deliver results. We continue to be impressed by the discipline and approach taken by the entire team in order to defend our margins and focus on value creating activities.

We continue to gain greater appreciation of the flexibility and resiliency of our resource base. Our first quarter results demonstrate this resiliency and our focus on costs.

Please note that we've provided key second quarter 2015 guidance information in the attachments to our earnings release. I'll be happy to take any questions you may have on that information and on other aspects of our results during the Q&A portion of the call.

I'll now turn it back over Todd. Todd?

Thank you, Mark. In closing, we had a successful first quarter of 2015 by achieving new records for oil and overall production, continuing to reduce operating costs and improving in capital efficiency, and meeting our commitment to operating safely and responsibly.

The price environment presents us with many challenges, however. We are positioned to deliver our balance sheet and grow as prices normalize. While we have deferred many high return project opportunities until price rise, we are also identifying additional investments that should create value throughout the commodity cycle as we continue to refine our life of field plans for our assets.

We have the operating flexibility to adjust our program rapidly based on market conditions, and have the ability to shift basins and drive mechanisms to optimize returns while maintaining a predictable production profile.

We have a large inventory of conventional assets that have relatively low decline rates and long production lives, and many of these conventional development projects are expected to be repeatable with low technical risk.

We are using this environment to improve our cost structure, implement efficiencies across all functions of the business, and improve the project economics of our portfolio of investment opportunities so that we can rapidly take advantage of a more favorable commodity price environment in the future.

We continue to be very excited about CRC's opportunities, and are diligently working to make the improvements needed, including deleveraging, to increase shareholder value.

This concludes our remarks, and we now welcome your questions.

Thank you, sir. (Operator instructions.) Doug Leggate, Bank of America.

Thanks. Good afternoon, everybody. Mark, I wonder -- I don't know if I misheard you on your sort of debt trajectory or guidance, if you can call it that, through the end of the year. I wonder if I could just ask you to repeat that, but also embedded in there the deleveraging options. Would you care to rank how you would see the priorities or the list or the menu, if you like, of the different options that you have, and specifically addressing whether you'd be prepared to allow the operating costs to bump a little higher in order to monetize some midstream? And I've got a follow up, please.

Hey, Doug. This is Todd. I think in my comments you'll see that we talked about our quarter end debt balance is around $6.6 billion. And we expect that to essentially be the same as it would be unless we had some other kind of deleveraging event occur at year-end, so effectively flat with this -- now that we've had all the effects of our former parent work its way through the balance sheet.

With regard to the deleveraging options, I think effectively -- if you think about the two buckets, midstream and upstream, midstream is effectively taking and putting some kind of fee or other structure on your income statement for the opportunity to de-lever the balance sheet side. So, yes, there is that opportunity on that side.

The other deleveraging options you look at on the upstream side are all kinds of asset monetizations, but we're not particularly married to any particular one. We're trying to find what's best for CRC and what has the optimal outcome from both a deleveraging standpoint and an operational standpoint and tax consequences and other issues.

So, what I'd say now is we have identified most of those opportunities and now we're working through all the details and refining it to understand all the implications, particularly on our operations going forward.

And what's your follow up, Doug?

Sorry, Todd. Just to be clear on that flat debt, what oil price assumption are you making? Does that assume any improvement? Because you talked about 75% of incremental free cash flow going to the balance sheet. So, are you assuming that there is no recovery in the oil price in the second half, or what was your assumption there when you make that statement about the debt?

Yes, that's a price lower than we are today. And it's a price closer to $60.00 Brent as opposed to where we sit today.

And you're right. If we had a sustained high oil price, I think differentially we'd spend probably 75/25, 75% towards debt pay down and 25% investing in the business if we were able to see that this higher price environment we're in today is sustainable.

Okay. Thanks. My follow up is really more about the capital efficiency of the portfolio. So, you drilled 55 wells for $133 million. The majority of those were steamflood. Can you give us some idea -- obviously there's a lag on the way these things behave. But, what would you expect to be the aggregate peak or plateau production contribution from the average well in your -- that's in your program right now? And when would you anticipate to see that contribution kick in? I'll leave it there. Thanks.

Aggregate? I mean, we did have some waterflood wells in there too and steamflood wells. I think we could safely say, if you aggregated it all, probably about 150 barrel a day equivalent, but we're really talking about oil here.

Per well?

Yes, I think that's a good average.

Across the 55 wells?

Yes.

All right, got it. Okay. Thanks very much.

And you're talking about plateau, so yes.

Yes, that's right. Yes. Thanks very much.

Paul Sankey, Wolfe Research.

Good afternoon, everyone. Just stepping back to a higher level and then I have a specific one that follows up from that, but I guess are we looking at a strategy here that's changed towards a maintenance capital strategy with the maximization of free cash flow as a priority, which you've then explained will be a delevering strategy? And can you just run again through what you think your maintenance capital levels are? Because there's been a tremendous amount of debate on whether the $450 million a year is really a number that can hold you flat on an ongoing basis, if that was necessary.

If we were to stay in a relatively low oil price environment, which I guess seems to be around the $60.00 mark based on what you're saying, where would you maintenance capital be next year to stay flat is I guess what I'm driving at, right?

Yes, Paul. Thanks. I think the issue really is we were dealt a balance sheet we had in an entirely different product price environment. And we got the credit amendment to buy us the time to square away our balance sheet, and that's what we're undertaking at this point in time and putting our balance sheet in order.

And as we've told people, if you think about mid-cycle economics, we'd like to have a debt to EBITDA of around two times. So, clearly we're not in that environment today, but we don't think this is a mid-cycle type price.

So, we're trying to work our deleveraging options to get that squared away. And you're right, that is contrary to what we've said. But, we also did say we would live within our means and our cash flow, and that's what we're doing effectively by this. We even have some debt pay down built into our current capital structure.

So, the maintenance capital question, on that question I think it's not the $440 -- or $450 million that you quoted, that you talked about. I think that's going to hold -- for this year, clearly it's going to hold our oil modestly flat to up. If we continued in a very -- this lower price environment for next year at a modest increase, we think it would be -- oil would be essentially flat and BOEs would decline, like we talked about.

But, if you wanted to talk about maintenance capital from a BOE perspective, we haven't really put that out there, because we don't really look at the gas investments in the same light using our VCI. So, it's really oil focused, and that's why you see us really focusing on maintaining our oil production as our top priority.

Yes, I understand that. So, basically what you're saying is that you think, with a modest increase from the $450 million, you can maintain the oil volumes flat next year if necessary with a strategy essentially of delevering down to the target that you outlined of two times.

Yes. I don't think we'll get there overnight, clearly, in the two times. I don't think there's one single magic bullet, but we're looking at a lot of different options that we think will help us get there.

Understood. And then, the price at which you would turn more optimistic, if you want, in terms of perhaps re-pursuing growth. Can you give us a sense for where that price would be?

Well, just sitting in today's current environment, if we could see a sustainable $70.00 price, I think we might start thinking about more activity and some debt pay down.

But, really from our standpoint, it has to be sustainable. As Mark likes to say, we have to be able to touch it and feel it and hug it and feel good about it. So, until we get to that environment, I don't think we're going to make any dramatic changes.

I think you would have to return back to -- from a growth perspective, I think we have that potential to grow off of our lower declining base. But, I think you want to think about getting past the debt environment first before you really think about -- and deleveraging before we think about growing the business.

Understood. I look forward to the day that I cover oil and I can touch, feel, and hug the oil price. That would be a happy day for me too.

But, the specific question was that the CapEx you announced at the quarter I think was $133 million. But, the press release has cash used in investing activities at minus $313 million. I hope that makes sense to you. Can you explain that difference for me?

Carryover from last year, Paul.

Sorry? There's a kind of a headline CapEx of $133 million, but the press release has cash used in investing activities of $313 million, nearly more than double that.

Hey, Paul, it's Todd. I think what Mark was trying to tell you is that effectively when we were spun off, in addition to the $6 billion in debt we had -- at the spin off date, they took our receivables and left us with the payables. So, you have some working capital working its way through the first quarter.

And so, that's effectively the difference. That's why we say now all the effects of the payments to our prior parent have now worked their way effectively through the system now at the end of this quarter.

Right. You answered the question. Great. Thank you.

Evan Calio, Morgan Stanley.

Hey, good evening, guys. Long day. Let me follow up on the deleveraging efforts. Any potential target for deleveraging from these transactions? I mean, can you dimension range of amounts? Is this up to $1 billion, or any range? And is the targeted timeline to close by year-end?

Yes. Hi, Evan. Yes, I think the -- if you think about it, looking at our debt, we have $5 billion of bonds. We have $1 billion term loan that's pre-payable. And we have our $600 million of working capital that's on our facility.

So, if you think about what's the easy things to pay down, clearly the facility and the term loan. And then, you could -- the bonds, the first maturity that's coming up is 2019. So, clearly you could buy some time there, or try to be opportunistic.

But, our bonds are no longer trading in the high 70s, low 80s. They're trading in the mid 90s. So, I don't think that's as easy, to buyback and then get the effects of that at this point in time.

But, I think our short term, if you want to think about it, or medium term target here is really to attack that $1.6 billion that we can. And we would hope to have one or two of these things closed by year-end, but for sure signed up and maybe we're working through all the legal paperwork at that point in time.

Right. So, you mean one or two transactions up to $1.6 billion, not the deleveraging via cash flow. Did I understand that correctly?

Yes. I mean, we could -- it depends on what happens to the product prices. So, I mean, if something happened on a geopolitical level in the Middle East that dramatically drove up oil prices, clearly we would differentially spend the excess cash flow towards debt pay downs in addition.

So, that would be in that $1.6 billion number. But, at this point in time, it might be one, it might be two, it might be three, because we're still working through and getting all the details on all these deleveraging options.

And so, the consideration, it sounds like it's beyond just midstream assets into upstream assets, if that's the case, is that -- potentially. Is that accurate?

Yes. I mean, we're pursuing all options and everything's on the table. So, I think that if you saw something from the standpoint of something that made sense.

Clearly, we don't want to monetize upstream assets in the bottom of a cycle. But, there are some creative structures where you can, in effect, get the kind of valuations you would like to get and do some kind of joint ventures or monetizations that way. But, we're looking at a lot of different ways and a lot of creative ways going forward.

Great. And maybe a different question on the CapEx. I know Paul handled the maintenance question. But, I know you've lowered CapEx in the current environment, but do you have a different or a lower CapEx view of what it would cost to grow the company the 6% to 9%, which was your prior target? I know now you'll have some debt pay down, or 75% debt pay down on some of that cash sweep. I mean, is that still a $2 billion kind of number, or is that also lower in this -- as you've kind of gone through and removed costs?

I think it's definitely lower, but it's not a way we're really looking at things at this point in time, given we're starting at the screen we're staring at today. But, yes, I think it's definitely substantially lower than the number you quoted, but it's not where we're at today, clearly.

Yes, that was just more of a -- like a historic number.

No, it's not anywhere close to that. That included a lot of things, including some infrastructure spending and some capital that we wouldn't have spent under the way we are allocating our capital.

And then, just last one for me just to square the circle. So, in terms of spending the $600 million for maintenance CapEx, and I may have missed the number, of the oil CapEx, right? So, whatever you're saying is kind of maintenance oil CapEx, right, to offset a decline. What is the base decline that you're offsetting with that amount?

Yes. If you think about it, when we look at our reserves at year-end, with no downtime whatsoever, our base decline is about 10%. But, if you factor in historical downtime, it's around 15%.

I'd say that we've had an exceptional first quarter with regard to downtime, probably the best we've ever seen here in California. So, clearly we're closer probably to the 10% than we are the 15%. But, luck will turn against you at some point in time as things, ESPs and rod pumps and everything else, fail.

But, we've been doing an exceptional job on our base production. And so, hopefully that gives you the guidepost that you need.

Great. I appreciate that. Thank you.

Thanks, Evan.

James Spicer, Wells Fargo.

Yes. Hi, everybody. A couple of my questions have been addressed. I just have one follow up. And that's on your fourth quarter call you talked about a $300 million contraction in working capital due to the drop in the rigs. And it looks like you have positive cash flow from operations of about $115 million this quarter. Just wondering whether that $300 million is flowing through. And the context is really, I think, that last quarter, if I remember correctly, you said that you had $360 million drawn on your revolver and you expected to end 2015 at that same level. So, I'm just trying to sort of triangulate as to what the cash flow trajectory is here for the remainder of the year.

Yes. I think if you look at it, it's in the investment portion also. So, it's not all in the operations section. It's just a classification. And there might be a little bit more to work its way through the funds flow statement as we get some weight, payables and receivables.

Okay. So, if you're -- but, if you're going to end the year still at that $360 million of revolver draw, that would imply that you're going to be free cash flow positive for the remaining three quarters of the year.

I believe that's right.

Okay. That answers my question then. Thank you.

David Meats, Morningstar.

Thanks, guys. I just wanted to kind of revisit the maintenance issue a little bit, reframe that question. I was just wondering how long can you maintain the strategy of just focusing on the steamfloods and the waterfloods to hold your oil production flat. I mean, you mentioned probably 2016, but is that something that can carry on indefinitely?

I don't -- no, you can't carry it on indefinitely. But, I think for the foreseeable future we clearly have an enormous amount of inventory to execute on that front, as we said, through 2016.

I think -- as we get into 2017, I think it inches up from there. But, we still have an awful lot of steamfloods and waterfloods. I think you might hit a cycle too where you need a little bit more facility if you got -- capital if you get into 2017 also, because that ebbs and flows with the patterns as you implement your pattern development in the steamfloods and the waterfloods.

Okay. And you guys talked about JVs already. Is there anything that you would consider an outright sale of on the E&P side?

I think we would contemplate that, but it's all a matter of valuation. If you want to give us a valuation based not on the current strip but a different strip and different economic measures than the traditional ones used by E&P players where it's very strategic in nature, it's something we'd contemplate.

Again, like I said, nothing's off the table. But, there's not a lot of people that value things from a strategic level, capturing the resource that way as opposed to using some kind of net present value measure of the current product price strip.

Okay, fair enough. I think the rest of my questions have already been dealt with, so I'm going to hop out here and let someone else in. Thank you.

Sean Sneeden, Oppenheimer.

Hi. Thank you for taking the questions. Maybe, Todd, for you as a follow on the PDP decline, I was wondering if you could kind of help us understand maybe the decline for oil and gas separately. Presumably one is going to be a little bit sharper than the other. But, how should we be thinking about that going forward?

Yes. So, I think it's probably easier to think about it on a drive mechanism basis. So, if you thought about it -- and we could talk a little bit about oil too. But, because steamfloods are 100% oil, usually it's kind of mid single digits type decline when it's got past its plateau.

Waterfloods, a waterflood is typically 5% to 10% decline if you have one that's -- but if you're in a pace like Wilmington, it could be higher than that, but that's really mature. So, if you think about it as the -- most of our waterfloods are going to be in the 5% to 10% decline.

Other opportunities, if you thought about our unconventional, think about it in two different buckets, our shales, which we didn't invest -- aren't investing in this year, usually have first year declines of 25%, 30%. And I think those are rolling off and flattening out as we get into the second and third year past that.

If you want to talk pure natural gas declines in the Sacramento Basin, and we haven't drilled any wells there recently, but those have typically higher decline on new production there. That might be more 25% type declines.

But, that's just dry gas and that's a very small part of what we do at this point in time. It's a contingent resource if gas prices ever got up into -- with a four-handle.

Hopefully that's helpful. I mean, it's a -- most of our oil is probably mid to slightly higher single digits.

Okay. That's helpful. And I might follow up with you guys offline on that. I guess the second question is just kind of more conceptual around a potential kind of upstream deal. I guess just kind of curious how you think about it, but it sounds like the real preference is to de-lever. And just kind of considering where leverage is going this year, I'm kind of curious how you'd think about getting a upstream deal done that would be deleveraging versus more of a traditional kind of midstream deal which probably fits into that deleveraging ballpark.

Yes, you're right. I mean, the market for yield vehicles off of midstream assets hasn't -- there's plenty of liquidity there. I think in the upstream side, it's a little different.

But, I'd also tell you California's a little different. I mean, we have a unique set of assets out here, particularly our exploration acreage. And for years under our prior parent, we didn't solicit or really ever take partners and there's been a lot of people hovering around.

And if you understood the California oil and gas landscape, you'd know you might be able to get a little lease from a farmer here and there, but pretty soon you're going to bump up against CRC. And if you want to have any significant exposure to oil and gas resource here, you have to partner with us.

So, I think the people that have been hovering around for years who are interested in the state and interested in wildcatting are now still interested, and obviously realize this might be their one opportunity in this environment to get into the opportunity set we have.

And I would take it as some kind of cash and carry type deal, but you just never know how that would turn into it. But, we have more than enough parties that are interested on the exploration and exploitation side of our asset base.

Okay. No, that's helpful. Thank you very much.

Pavel Molchanov, Raymond James.

Hey, guys. It's Pavel. A quick question on realized pricing. In the past, there have been times when your realized pricing was above WTI. I think in the quarter it averaged about $2.00 below WTI. As your production and presumably other producers in California kind of goes lower, do you think that premium is likely to emerge again?

You have to think about our production as being tied to Brent as opposed to WTI. We're in effectively a closed market for crude oil production and marketing and distribution. So, we have an R squared of over 80% to Brent.

So, we guided down because when you have this closed system -- we had the discrete events at Torrance and the nationwide refinery strike. That brought down the differentials in the quarter. But, when the refinery strike came back, we can see them starting to get better in the state.

But, again, I think your benchmark is better to tie into Brent than it is to WTI.

Okay. Or maybe I'll ask it a little differently. The spread versus Brent went from single digits last year to 15% this past quarter. Do you see that narrowing back down as in-state volumes decline over time?

Yes, I think so, because that's what you're competing against. But also, if you have an institution of -- and you get rid of the export ban, that clearly will bring it more into parity over time. And so, effectively you're going to have them be very close to each other, and just the WTI will represent maybe a pricing -- transportation from the Gulf Coast to Cushing.

Okay. And then, one more question on your hedge book. Given the extent of contango in both Brent and WTI at the moment, are you layering any hedges for 2016 right now?

As you can see, we didn't -- we haven't layered in any yet. We continue to look at the markets and be opportunistic. We're towards the bottom of the cycle here, so it's not the perfect time to implement a hedging strategy.

But, you got to remember too how options are priced. Time and volatility are the most important things, so the further you go out in time the more you're going to pay for it.

So, we're just trying to be opportunistic and look for technical dislocations on days where we feel like we can lock in some hedges that make sense for us, and hope the price environment continues where it's at and inches a little bit further higher.

All right. Appreciate it. Thanks, guys.

Brad Lundy, Ivory Capital.

Hi. Thanks for taking the question. Just wanted to clarify, were you referencing oil production guidance as effectively flat Q2 versus Q1?

Yes, that's what we said.

Okay, perfect. So, if I step back and look at it, you're actually growing oil production from Q4 exit, right, Q1, Q2 through the year on $440 million of total CapEx. Wouldn't that suggest kind of the maintenance CapEx profile of the business is actually below $440 million on an oil only basis?

No, I think we have some -- a little bit of headwinds coming into the year from some facility spending, and we're frontend loading. The $133 million we spent in the first quarter, that's more facilities. And so, I think that you're going to see that's still a little bit low from oil maintenance CapEx.

Got you. And how should we think about the cadence of that oil production profile as you get through into the back half of the year?

Yes, I think you could probably extrapolate it and look at what we've said about the -- year-over-year, we should average very close to, if not essentially the same, as last year, 159,000 BOE. And I think if you extrapolated that linearly, you wouldn't be dramatically off.

Perfect. Thank you.

Gregg Brody, Bank of America Merrill Lynch.

Hey, guys, just a couple questions for you. You mentioned the two times leverage target based on a sort of a normalized oil price. Are you willing to share what you think that normalized oil price is?

I think that what I will say is that we're trying to gear up our organization from a G&A standpoint going forward to be right sized at $75.00 Brent.

And the one other question was you mentioned your policy for hedging. I think you mentioned that 12 to 24 month policy. Could you just repeat what the policy is? And sort of how hard and fast is that now?

Yes, 12 to 18. I think we're clearly looking to implement that. And as we get back to what we consider more mid-cycle prices, we'll continue to layer in hedges and underpin our capital program and our cash flows.

And was there a percentage you were targeting for 12 to 18 months?

I think if we got in a normalized environment we'd want to hedge at least 50%.

Got it. That's very helpful. Thank you, guys.

Gary Stromberg, Barclays.

Hi. Thanks for taking my call. I just wanted to dig in a little bit on cost trends in first quarter of 2015 and then the rest of the year. I guess I was surprised to see unit operating costs going up from $16.07 to $16.20, and then guidance I think is up another 5% in the second quarter. So, just wanted to get a sense for trends on the operating cost line in the first and second quarter and the rest of the year, and the same thing with G&A. It looks like G&A is projected to be up second quarter versus first quarter.

No, I think if you look at, on an absolute basis, the operating costs were down. It's just when you think about the number of days are shorter in the first quarter. So, on $16.07 to $16.20, it's effectively almost flat.

I think when you think about California and the peak energy season, the peak rates start accruing really in the second and third quarter. So, you'll see that creep up. We're hoping to claw back that as much as possible from operational efficiencies. But, again, we're guiding to what we think as we know today.

But, yes, the first and the fourth quarter are typically the lowest price energy costs going forward. And I think if you look at the G&A, you got to remember bonuses are paid in the first quarter.

Okay. So, the trend beyond the second quarter in operating costs, your second quarter guidance is $16.70 to $17.20 in a deflationary oilfield service environment. Would that move down from that level, or is that a pretty good level going forward?

I think it's pretty good. That's what we gave as guidance. I mean, obviously we strive to be under it.

Okay. That's all I had. Thank you.

Doug Leggate, Bank of America.

Sorry, guys. I tried to stick to the two question rule so I got back in queue. Just two quick follows ups, if I may. Todd, it's really -- the comment you made about a couple of transactions, turn of the year type of commentary. You said if not closed, then definitely signed. It sounds like you already have some line of sight, so I'm just wondering if you can kind of characterize what inning are you in in terms of this negotiation. Are we just getting started out of the gate, or do you already have line of sight as to where we're going to see some of the deleveraging? And I do have a follow up, please.

I think we've cast our net as wide as possible. We're now looking through our suite of options and kind of going through the details and trying to refine things from a tax perspective, operational considerations, and ultimately proceeds.

So, I think at this point in time we're working through the details to understand all the different opportunities we're looking at. I think it's early on, but we're not far away from, once we have that refined, where we could start looking to execute with one or more parties.

Some of these are more complex than others and require more tax attorneys and regular attorneys than others. But, that's why I think that we'll have something signed up at least, or if not closed by year-end.

To be clear, are you in active discussions today with third parties?

We are discussing a variety of different opportunities with different folks. I don't think you could call it active negotiations, but we're clearly discussing a lot of different opportunities as we cast a wide net to everyone in looking at that at this point in time.

Okay. My follow up is almost a reverse hedging question. Gas is obviously very depressed. It's a big part of your cost basis. Any consideration of hedging to lock in low gas prices as opposed to high oil prices, so to speak?

Yes, Doug, I think you've been looking at the California basis. California has had a very mild winter. 90% of natural gas is imported. Typically it trades at $0.10 to $0.15 premium to Nymex. That's collapsed quite a bit.

And so, yes, I think there's an opportunity, if this mild weather continues and storage in California is relatively full, to potentially lock in some lower natural gas prices as a feedstock for our steamfloods.

That's great. Thanks a lot.

Evan Calio, Morgan Stanley.

Hey, guys, just one quick follow up for me if you have it. I didn't know if there is any quantification of cash flow related to the cryo plant or the power plant on a standalone basis. Have you got any ways to think about that?

Yes, I think there isn't because it's integrated currently as operations. So, if you think about it from the standpoint of -- and the way we like to talk to people is we have around 50 million barrels of equivalent production. And if you thought about it from the standpoint of layering on a $1.00 fee or operating cost charge, however you want to call it or structure it, that's $50 million a year you could put in of EBITDA and create, or $2.00 obviously $100 million.

So, that's kind of, I think, the boundary conditions, what we look at when we think about what we could layer on to our operations and sustain. So, I think hopefully that gives you some idea along those lines.

That's great. And when you gave the kind of number of potential, it could be up to $1.6 billion, is that -- that's pre-tax, after-tax?

That would be what we take account, because obviously we want to pay down the $1.6 billion. And that's after-tax dollars. We hope to get there through a variety of ways.

Sounds good. Thank you.

That will conclude our question and answer session. I would now like to turn the conference back over to management for any closing remarks. Gentlemen?

I'd like to thank everyone for joining CRC's first quarter 2015 conference call. We look forward to seeing you out at the various conferences and on our second quarter earnings call. Thank you.