California Resources Corp (CRC) 2017 Q3 法說會逐字稿

Good afternoon, and welcome to the California Resources Corporation Third Quarter Earnings Conference Call. (Operator Instructions) Please also note that today's event is being recorded. At this time I would like to turn the conference call over to Mr. Scott Espenshade. Sir, please go ahead.

Thank you. I'm Scott Espenshade, Vice President of Investor Relations. Welcome to California Resources Corporation's Third Quarter 2017 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; as well as several members of the CRC executive team. I'd like to highlight that we have provided slides in our Investor Relations section of our website, in our Investor Relations section of our website, www.crc.com. These slides provide additional insights into our operations and our third quarter results and additional information.

Also information reconciling non-GAAP financial measures discussed to their most directly comparable GAAP financial measures is available in the Investor Relations portion of our website and in our earnings release.

Today's conference call contains certain projections and other forward-looking statements within the meaning of federal security 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-Q, which is being filed by Thursday. We would ask that you review it when available and the cautionary statement in our earnings release. A replay and transcript will be made available on our website following today's call and will be available for at least 30 days following the call.

As a reminder, we have allotted a similar time for earnings Q&A at the end of our prepared remarks 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 welcome to today's earnings call. Our performance for the third quarter of 2017 reflects our ongoing commitment to invest in CRC's world class resources in a disciplined, value driven way. We continue to deliver on our promise to live within our cash flow while also delveraging our balance sheet to enhance our financial flexibility.

We are proactively managing our business in response to the price environment by utilizing the optionality provided by our asset base, joint venture agreement and balance sheet enhancement opportunity.

With CRC's value creation index, of VCI, as our guiding principle, we continue to focus on value and execute against our operational and financial goals and create the flexibility we need to navigate the path ahead.

Strengthening our balance sheet has been and remains CRC's highest business priority. During the quarter, we used free cash flow to reduce our bank debt by $30 million and are proactively taking steps to extend our debt maturity.

Our bank group has reaffirmed our $2.3 billion borrowing base and continues to provide strong support as we received approval on a proposed amendment of our credit agreement.

The amendment, which was approved by 100% of our bank group, subject to certain conditions, would extend the term of the bank facility by two years to 2021 and relax the financial covenants to provide additional financial flexibility. Mark will talk in more detail about these and other updated financial items.

We spoke last quarter about a ramp up in both our capital program and activity. We experienced some vendor onboarding and equipment issues and growing from no rigs one year ago to our current fleet of nine rigs, which slowed our ramp up in production. That said, we saw crude oil production bottom out this summer and witnessed modest increases for oil production on a gross operated basis late in the third quarter.

On a new basis for the third quarter, we produced approximately 128,000 barrels of oil equivalent per day, within our guidance. As expected, our crude oil production has flattened, in line with increased capital investment of $75 million to $100 million per quarter. Recall that with our PSC contracts in our Wilmington field, we are paid in barrels. In higher price environments we receive fewer barrels and we see this knock-on effect in our production costs.

Looking at our performance year to date, I am proud of what we have accomplished. Our team successfully navigated several operational challenges, have done an outstanding job maintaining our base production. Our team also operated safely, avoiding heat issues, despite facing 100 plus degree temperatures for more than 50 days in the San Joaquin Valley during the third quarter.

We consolidated our Buena Vista Nose facility with the greater Elk Hills infrastructure and realized synergies and cost savings. This enables us to centralize operations and eliminate the need for gas compression. As a result, the process is so efficient that we're able to have wells online 36 to 48 hours after completion.

Thanks to the diligence of our team, we've had many successes this year. We've ramped up to nine rigs and are generating free cash flow. This demonstrates the flexibility we have over our operations, the predictability of our resilient base and the character of our organization.

The important takeaway is that CRC has the ability to manage the business throughout the cycle. We have clearly demonstrated that our team and our resources can deliver through a sustained downturn. Our production results validate the low capital intensity and low decline nature of our resource space. And going forward, we remain focused on sustained activity within cash flow to continue to drive production momentum.

In addition, CRC further distinguishes itself through our clear focus on value. From day one of our spinoff, we have stated that we are a value driven business. Our key investment decisions are based on our VCI. Through the VCI metrics, CRC applies a highly disciplined approach to allocate capital across our resources. This is essentially a discounted profitability index that measures bang for our investment buck. It's a tool that separates us from companies that pursue growth for growth's sake that leaves them cash flow negative.

To date, our teams are executing a drilling program with an expected VCI of 1.7 and has completed 250 work overs with an average VCI of 3.3. This is far above our 1.3 VCI investment threshold.

Let's now walk through key performance factors for the third quarter, which highlight the way in which our assets are responding to our operational plan.

Our asset base is benefiting from rigorous production surveillance efforts and is responding to increased drilling activity. During the third quarter, we nearly tripled the rig count from an average of three rigs in the second quarter to an average of eight rigs. In the third quarter alone, we also nearly doubled our 2016 wells drilled to 77 and invested approximately $100 million of capital.

Through improved well design and planning, we've been able to create additional efficiency. For example, in the 29R shale, we eliminated a string of casing to safely and effectively optimize this deeper drilling program. Recent wells in this area are coming in approximately 29% lower on a per dollar per foot basis while drilling 12% deeper since we last drilled in the area as referenced on slide 10. These efficiencies reduced total well costs by 20%.

We have also taken a similar approach at Buena Vista Hills, as well as Buena Vista Nose to deliver incremental economics. We believe we continue to apply efficiencies such as these on a broader basis.

We are building momentum through our recently signed JVs with BSP and MIRA and we are pleased to see our relationships grow. Our JV partnerships serve to enhance our portfolio flexibility with high margin production growth, accelerating value and derisking inventory.

Part of the added benefit behind these agreements is that they facilitate our ability to maintain a full suite of activity to enhance efficiency and in achieving critical mass for services and build inventory for CRC inside and outside of our JV specific area. We believe the combination of our JV activity and the resumption of our CRC funded drilling program will enhance our inventory and production into 2018.

We've been opportunistic with the recent increase in oil prices. We layered in additional oil hedges in the third quarter that provided added protection in the fourth quarter of 2017 and for 2018. Today we have contracts protecting 29,000 barrels of oil per day in the first half of 2018 and 19,000 barrels of oil per day in the second half of 2018 with [strike] prices at approximately 60 Brent or above. For additional details, please see slide 17.

We will continue to strategically layer in additional hedges to line our capital investment with projected cash flow. We typically consider a target of about 50% of our expected quarterly crude oil production as adequate hedging, given our high level of operating control.

The alignment of California's waterborne imports with the Brent crude oil market has improved our realization. In the third quarter, as Brent crude prices and realizations increased, our price differential to WTI also strengthened. We believe these dynamics were supported by the increased global demand for medium and heavy barrels and fewer waterborne barrels available.

We benefit from a large diverse portfolio of assets and applied sophisticated portfolio management underpins our value driven approach. It's a dynamic portfolio that provides flexibility not only to adjust our projects in line with the commodity environment, but also enables us to strategically pursue a variety of projects. Specifically we're able to target wells based on VCI complemented by a combination of cash payback, reserve potential and production growth. We believe the resulting portfolio effect provides CRC with a competitive advantage.

As we look to thoughtfully increase activity and extend field limit throughout our top asset, CRC's portfolio provides us with multiple ways to achieve target outcomes and contribute to our strong base of production.

Over the quarter, we once again adhered to our commitment to capital discipline and philosophy of living with cash flow. These principles aren't aspirational for us, that's how we operate day in and day out. In addition, by utilizing JV capital increased activity levels and derisk inventory, we created optionality to flex CRC capital, remain within cash flow and direct our resources to the highest value opportunity.

Looking ahead as we survey the oil and gas sector, we see that inventories are being drawn down due to solid demand and current global undersupply of crude oil. California's chronic dependence on energy imports continues with 12% of the country's population in the Golden State accounting for 58% of the net energy imports into the entire United States.

While our crystal ball is no better than anyone else's we do see that decline rates are increasing in the lower 48, which implies increased maintenance capital for the sector. Conversely, CRC's low decline rate remains a standout in that regard, as slide 9 attests.

For CRC, our formula for success is simple. We will continue to be laser focused on value. We are optimizing our rich asset base, living within our cash flow and delevering the balance sheet to create long-term value for our investors. These principles will continue to guide us into 2018. The excellent optionality of our flexible portfolio positions CRC well for the future.

I will now turn the call over to Mark to discuss the details of our third quarter results, as well as other financial matters.

Thanks, Todd. Before we dive into the numbers, I'd like to first set the stage and share our perspective on the current environment. Crude oil rallied in September, particularly Brent, on moderating industry production expectations, which we see as a positive for the sector overall. Additionally, we've seen a transition in the forward curve from Contango to slide back (inaudible), which has, and should continue to incentivize fewer barrels in storage further supporting price.

Due to CRC's diligent workforce and flexible business model, we've been able to adjust and manage our activity level to match fluctuations in the commodity price environment.

With those dynamics in play, I'm pleased to report that we've made progress on many fronts. As we noted last quarter, our preference was to deal with our balance sheet in order of maturity and to ultimately extend our runway. We have approval on an amendment from all 29 of the lenders and financial institutions that extend credit to CRC through our 2014 credit facility. This amendment will extend our bank facilities two years to 2021 subject to a spring in maturity and modify and relax key covenants. We expect that the amendment will be signed by the lenders after confirmatory federal flood insurance diligence. Once signed, the amendment will become effective after certain conditions are met, including completion of a new money raise.

Our borrowing base was also recently reaffirmed at $2.3 billion. This compares to our PV10 value of $5.1 billion that was run with a strip price as of September 29, which is approximately $55 Brent and fairly flat. Note that it's about 10% lower than today's strip price.

Our ability to work constructively with our lenders to maintain our borrowing base, extend our maturity and receive improved covenant flexibility validates the endorsement we have from our lenders and underscores our deep understanding of the considerable value of our asset base and our resilient business model.

We continue to work other avenues to strengthen the balance sheet. As we've said in the past, this will be an iterative process. We're monitoring capital and property markets and will pursue opportunistic balance sheet enhancing transactions when prudent.

We have increased capital investment this year for the first time since the spin. During the quarter, we drilled 46 steamfloods, 21 waterfloods, 6 primary and 4 unconventional wells. This activity's nearly doubled last year's full-year of drilling in the third quarter alone. We're particularly excited about our initial results in the Buena Vista area and have had additional successes with horizontal redevelopment wells, targeting attic oil in Wilmington.

We continue to gain earnings as we delineate our high potential fields and make progress in reducing our overall drill times. With the introduction of joint venture capital, we were able to reduce our initial internally funded capital plan from $300 million to roughly $250 million. Our view remains in line with our overall activity that we expected at the beginning of the year, our conventional fields with large vertical sections of reservoir are typically drilled as directional vertical wells and don't require the large completion costs of typical unconventional wells in other states.

As a result, we're not subject to the same sand, water or completion equipment cost escalation and infrastructure constraint as peers experienced in other basins. We see this as a market differentiator when compared to other regions.

For the third quarter, we produced an average of 128,000 barrels of oil equivalent per day. This figure included approximately 1,000 BOE per day of negative PFC effects due to higher realized prices compared to those at the time of our guidance. This result was flat with the prior quarter and represented a year over year decline of approximately 7%. Our base production continues to showcase the resilient nature of our asset and low decline rate.

As you can see on slide 9, our quarterly presentation materials outlined decline rates across other companies. CRC is to the far right of the graph. With a large portion of our drilling activity directed toward joint ventures, overall production should increase, while the standalone effect to CRC will be more muted in the near term. Our teams have performed well in executing this deep ramp up and our drilling and work over activity and we continue to see favorable responses from our asset base.

It's important to keep in mind that California's the world's sixth largest economy and the state uses every barrel of oil we produce. A higher global and local demand resulted in realizations before hedges, which were 94% of Brent and 101% of WTI in the third quarter. A $48.90 realized oil price in the third quarter compares favorably to the $41.73 reported in the prior year period and reflects the California refiner's preference for native California crude. Settled hedges further enhanced our realization in the third quarter by $1.12 per barrel.

Realized NGL remained strong on a year over year basis as $34.63 or 72% of WTI. This result, compared to $22.45 in the prior year period, which reflected only 50% of WTI. The 54 % quarter over quarter increase in realized NGL prices reflected tighter domestic supplies, the strength of exports and higher contracted prices on natural gasoline. With the winter heating season fast approaching, we anticipate the strength in the NGL market to continue well into 2018.

The third quarter of 2017 realized natural gas price at $2.56 per MCF was 3% lower than the $2.64 realized in the prior year period, but strengthened 4% from the second quarter of 2017. Prices continue to be affected by lower regional production levels, ongoing curtailment of third part gas storage and higher demand in the state.

Increased activity levels in conjunction with higher electricity prices resulted in $11 million increase in production costs in the third quarter of 5% from the prior year period. Much of the increase related to increased well repair to produce down time, infrastructure maintenance or elected well work. This elected well work was largely driven by the improved economics resulting from the increase in commodity prices.

The lower quarterly production, including PSC effects, negatively affected costs on a per unit basis. Third quarter production costs of $18.90 per BOE fell just outside of our guidance range. As I mentioned, the improvement in prices from the time we set guidance resulted in 1,000 barrel per day negative BSE effect. Excluding this effect, our production costs would have been $18.76 per BOE.

Adjusted general and administrative costs were $5.28 per barrel in the third quarter, which was below the low end of our guidance. Interest expense of $85 million was lower on a year over year basis and in line with our guidance.

For the third quarter, we reported a net loss of $133 million or $3.11 per diluted share and an adjusted net loss of $52 million or $1.22 per diluted share. The adjusted net loss excluded $72 million of noncash hedge losses and net $9 million of other charges.

Adjusted EBITDAX for the third quarter of 2017 was $181 million, up 10% from $164 million in the prior year period and reflected margin expansion of 35%. EBITDAX was also up $23 million from the prior quarter.

CRC reported, operating cash flow of $105 million in the third quarter and generated $5 million of free cash flow after working capital. And despite the challenging commodity price environment, we're proud to have reported $35 million in free cash flow for the third quarter and $101 million for the first nine months of 2017, excluding capital funded by BSP.

These results demonstrate the capital discipline that we continue to apply in our business. Living within cash flow is not a new concept for us, it's something we've done since our inception.

We ended the quarter with a debt balance of $5.1 billion, down from $5.2 billion a year ago, reflecting our continued commitment to strengthening our balance sheet. Our asset base is responding to increased capital levels and we continue to align our organization for the commodity environment at hand. We believe that we're at a sustainable level of activity that allows us to live within cash flow, support the increased activity set from our joint venture partners and grow cash flow while maximizing value creation.

As I've discussed, we've taken steps to lengthen our maturity runway and continue to evaluate other opportunities to strengthen our balance sheet. So far in the fourth quarter, we've seen a handful of isolated third party power outages that have affected production in the period. These outages and other planned third party utility outages have been built into our guidance and account for over 1,000 barrels per day reduction. In addition to expected PSC effects in Wilmington amounting to another estimated 1,000 barrels per day.

For 2018 we expect to deploy ongoing capital to VCI ranked high value projects, live within cash flow and build momentum for production growth. Please note that we provide a detailed analysis of adjusted items, as well as key fourth quarter 2017 guidance information in the attachment to our earnings release and 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 to Todd.

Thanks, Mark. As our activity has ramped up to what we view as a sustainable level given available capital from cash flow and JV partners, it is important to review the key factors that drive our investment criteria and expected cash flow. These are the same criteria that have been in place since CRC's inception.

With our high level of operating control, we will flex our activity to meet our investment criteria. Our world class resource space has a low production decline that benefits us throughout the commodity cycle. California is a large highly (inaudible) province and we have the ability to increase production and drive EBITDAX growth for CRC.

Our focus is directed to deleveraging, recognizing that debt adjusted per share metrics influence market valuation. Things that are fashionable from time to time for some oil and gas producers, like living within cash flow, are part of CRC's core value and have been since our inception. We will continue to operate with character, responsibility and commitment to deliver for our investors as we look to exit 2017 on a strong note and deliver value in 2018 and beyond.

We now welcome your questions.

(Operator Instructions) Evan Calio, Morgan Stanley.

My first question is on CapEx. It looks like CapEx is lower for 2019 on slide six. Maybe you can mention the change since your last deck. And just generally, how do you think about 2018 in terms of organic spending to fund growth or generating free cash flow to delever the balance sheet?

Just flexing capital for -- I assume you meant 2018 --

Yes.

-- how we flex it with our joint venture partners. We're anticipating, as we've talked all along, that we think there's another joint venture either late this year, early next year, that will also augment that activity set, but it's not built into those numbers right now.

Right, but generally in terms of planning for 2018, how do you think about the balance between, again, on a strip kind of basing of either driving incremental growth with your cash flow or generating free cash flow to delever?

I think we'll look at it the same way we always look at it from a kind of a value perspective. I think when we look at where the strip is today, it's still fairly[validated], so we're planning probably modestly lower than what the strip has out there today. So from our perspective I think incremental dollars that came from free cash flow we take a hard look at deleveraging first and potential projects, but if something has an incredibly high VCI, I think you'll see us invest in that prior to deleveraging. So I think it's from that standpoint we look at it and where our debt's trading and really the value proposition. But understanding like we said, we know kind of job one is bringing the balance sheet in order, so incremental dollars, the bias is going to be towards deleveraging because it would have to be something that'd be very competitive on the value side. You want to look at overall based on prices today, I think the bias would be slightly up for our capital program for next year.

Maybe a second question if I could. You've gone from zero to nine rigs. Can you discuss I guess more of the details of -- you mentioned there were some issues in the ramp and has that modified or strengthened your ability to invest at that $1 billion to $1.5 billion within organizational capabilities? And then any update on the JV process, which you also -- I think you mentioned on the first answer.

Yes, I think there's nothing new on the JV. I still think we're actively in discussions with numerous folks on upstream and midstream opportunities that could be materializing by year end or early in 2018.

As we look at their activity ramp, I have to say compared to past cycles and activity ramps, we did an outstanding job. The timing was a little off, we had hoped to be where we were in the third quarter, probably closer to the middle of the year. But that's really all that happened. I think we were being more cautious. I mean top priority is safety and not to hurt anyone, so I think you saw us be a little more cautious at the ramp and it took a little bit longer than we anticipated. We were probably pushed back by a few months.

And that supported your view of the again $1 billion to $1.5 billion being organizational capabilities from a CapEx perspective?

No, I still think we're there when we talk about whether it's ours or JV capital and our ability to execute on (inaudible) utilizing that for development or exploration joint ventures or for our own purposes.

Paul Sankey, Wolfe Research.

The move in the oil price that we've seen just recently, I was wondering obviously you've made very clear what your priorities are and so on. But firstly, I was just wondering how fast that Brent price, whatever it's at, $64 and change, actually flows through to you and whether it makes much difference if there's (inaudible) or if there's some sort of technicality or how quickly do you get the benefit of that?

And then obviously the follow-up would be what really changes since we've had such a dramatic price and you've been so clear about outlining what your priorities are? Is it just a free cash flow thing or is there going to be a change to what you're doing because of the extra money?

I think as we look to manage the free cash flow, obviously the activity set -- we're going to look at that. But with regards to differentials and how we get paid, we track really closely to Brent. I mean clearly two-thirds of the oil in California is imported and it's waterborne imports and that's Brent pricing. We have a favorable pricing regime. We actually see today differentials even above what we showed last quarter as a percent of the Brent and well above -- over 100% of WTI.

We think it has a lot to do with the quality and the impurities in the medium and heavy barrels that are out there on the waterborne barrels. We have better quality sulfur and other impurities here in California, so there's a strong preference for pipeline and a native crude.

So the move is basically immediate and you're getting great differentials anyway, but there's the quality issue.

Yes.

And then is there anything -- and look, you've made it pretty clear exactly how you're handling this, but is there anything that changes? Because we've got $15 extra on the oil price perhaps than we had planned.

There's clearly some more projects on the inventory side. And I mean we talked about getting our borrowing base reaffirmed, but that was actually at a price deck that was significantly lower than the current strip. It was more representative of the 2016 strip. So I think from our perspective, we have an awful lot of inventory, so I think the joint venture market's even more stronger for us to bring.

Yes, I was slightly driving towards that. I wondered whether JVs were more or less likely at different prices.

Yes, I think that they're a lot more likely. The interest has picked up even more and I think when you look at -- obviously we've talked about payout on those and it's performance and price related. So we've had performance be better than what we anticipated and prices have improved, so I think as you look at things we're fairly bullish across the board, particularly on new joint ventures and our existing ones.

Yes, and so your appetite for joint ventures would be reduced by higher prices. They'd actually be the same or higher.

No, they'd be the same or higher because I think our inventory expands as prices go up. Particularly as you get above 60, a lot more of the shales become more intriguing.

Tarek Hamid, JPMorgan.

On the announced revolver transaction, can you maybe just talk a little bit about that? Kind of as I walk through it if I understand it looks like a capital rate, a couple of hundred million dollars of term line A paydown a couple of hundred million dollars for (inaudible) paydown and cash to the balance sheet. Is that sort of a far way to characterize it?

I'll give you a high level characterization. I'll Mark walk you the details. I mean from my perspective, we're extending our maturities two years, we're increasing liquidity. Two critical factors for us and I'll Mark walk you through the details of how it actually -- the mechanics of it.

Todd's right. The revolver commitments reduced -- assuming the new money raised, the revolver commitments will be reduced to $1 billion and the bank term loan will be downsized to $200 million. The maturity will be extended from 2019 to 2021 subject to us bringing maturity. The amortization of the term loan will be decreased, so it works to help improve our liquidity. And then we just received financial covenant relief on the leverage ratio interest coverage and minimum liquidity, further enhancing the liquidity I spoke about as well.

As for the issuance of the new term loan that you referred to, it'd be junior to the revolver and the bank term loan. And then the proceeds from the new money will be used to repay RBL borrowings and to decrease the size of the bank term loan to get it down to the levels that I talked about earlier.

And I think it's important to note that the effectiveness of the amendment is conditioned upon the new money raised and $500 million of minimum liquidity on a pro forma basis.

So to clarify, is that potential new term loan going to be senior to the existing first lien (inaudible)? Or(inaudible) junior?

The current construct is just subordinate in the waterfall to the senior bank facility and ahead of the existing first lien second out.

And just final point. And then you have room to repurchase $100 million of junior obligation. Is that my understanding as well?

That would be correct.

Brian Singer, Goldman Sachs.

I wanted to go back to the topic of asset sales (inaudible) monetization. We've talked a lot here about JVs and wondered if you're also considering close to (inaudible) straight sales or collateralizations or if our focus should be more on the JVs, as you've indicated so far on the call.

As we look at things we look at them in kind of the basket of upstream and midstream. I think on the upstream side we've been biased towards joint ventures. We have divested some small interests along the way and we do look at potential divestures of things that don't compete for capital at our portfolio or don't think that they'll compete for years in our portfolio. So that is out there and we have looked at some of these things. But again, it has to make sense from the standpoint of value from our perspective. Like I said all along, we're not conducting fire sales.

I think on the midstream side, we continue to look at monetization, but also understand monetizing any part of our midstream we're trading balance sheet leverage for income statement leverage. So anything there would have to be something that we think makes sense, that will reduce our absolute debt amount. And we think clearly there's an impetus to reduce our absolute debt amount, but we do know that in some cases we'll provide a slightly higher operating cost for ourselves.

And then can you talk a little more about that oil production trajectory (inaudible). And in the fourth quarter you set the guidance on a (inaudible) basis, so what oil looks like.

And then you had a comment in one of your slides just moving from defense to offense, and how (inaudible) thinking about here for 2018? And how does that impact the oil trajectory as we go through the year?

I think the oil trajectory from here we reach our inflection point and we think we're climbing out of the bottom of it here, flattening out at the bottom here. So from our perspective we think we're going to be growing from here and we'll be investing from joint venture and our own capital. So as we invest more joint venture capital, we do get some immediate benefit, but not a ton of immediate benefit. But we think our trajectory on oil production is in a growth mode and that's what we talk about offense and defense. From our perspective we've gone from sitting in a foxhole getting shelled and now we're finally getting out of the foxhole and moving forward at this point in time.

John Herrlin, Societe Generale.

For the downhole maintenance, were you just doing workovers, Todd?

Yes, in most cases it's workovers and bringing back production that's been offline.

Also, given the potential shortage in gas storage in California, you kind of alluded to it. What's the likelihood of you increasing any of your gas activity or are you just going to stay with oil?

We have actually increased a little bit of our gas activity. As you know, we've talked about we have an exploration prospect up there. We've had partners talk about it, the (inaudible) prospect. We've done some activity and workovers. And then active, not completely active, but it's something that I think you might see us try to joint venture and bring in some partners to do that with us. We have on a small scale, but I think a more large scale in the future. But I do think that gas in California is something that'll be -- the basis has got to get better because there's going to be shortages, particularly as the weather patterns change and the (inaudible) canyon being really at a minimal use facility at this point in time.

Last one for me is on hedging. Obviously you added a fair amount compared to last quarter, at least for the second half of 2018. Are you done or would you floor up some more?

I think when you pay for hedges, you pay for time and volatility, so we monitor that. And we could take off our calls if vol got down and prices came in the right spot. Or we could add more swaps or be creative as we go forward. I think our goal remains the same, to be about 50% or more hedge. 50% is our target, given our high level of operating control. And that's why you don't see us extending out years. You just pay too much typically for that time element of the offense. So I think you could see us probably looking to layer on more in the back half of the year eventually, but we'll look and do what we think makes the most sense.

James Spicer, Wells Fargo.

A couple of things. I'm wondering what does this higher oil price environment do to the timeline on reaching the hurdle rate for your joint ventures and benefiting from the reversion of that working interest?

I think it really, James, it goes back to what I said before. Performance and price. I think obviously this is higher than what we had anticipated from the curb. So as you accelerate the price and the cash flows, you're going to accelerate the point where that reversion occurs. And again, performance overall on both joint ventures has been better than what we expected. So I can't give you an exact answer, but clearly it'll be months if not maybe years, depending on how the price holds up.

Do you have a current estimate at this point as to when you might start to begin to realize those benefits?

No, I think we're not prepared to do that. I think if we look back at last year when we talked about this, we talked about it could be anywhere from two to four years, depending on price and performance. I think we're probably a little better off on the price and performance than we anticipated, so we're probably closer to the two than we are the four, but we're in that range. Because the well mix has changed and the partners have different reversion points, so again, you get into a lot of detail that we're not really prepared to talk about right now.

And then secondly just on the balance sheet here, pro forma for the new term loan and credit facility amendment, how much incremental secured debt capacity do you still have to do incremental liability management?

We've got two operative baskets, James. The first is the $4 billion basket that's imposed as a result of the unsecured on top of it. And then we've got a basket imposed by the second ounce, which is the greater of $2.2 billion or the borrowing base. So that currently would be $2.3 billion. So those are the two operative baskets that we had to work within. And with the proposed term loan we'll be working within that last basket.

So there are no incremental constraints put on those or incremental limitations by virtue of this new capital raise.

Not at the present time, but we're still in the capital raising process.

Sean Sneeden, Guggenheim.

Todd, I think you had kind of indicated in your prepared remarks that the current drilling program has a 1.7 BCI. I guess is that on your 2017 program or is that the current while they're drilling today in therefore more of a 2018 impact? And I guess the second part of that question would be if you have any kind of sense of what the general kind of payback period on what you're doing, under I guess '17, '18 program, that would be helpful.

So the 2017 program, and that was at a lower price deck. It was probably a $54, $55 pricing at that point in time with the VCI calculation. And the payback on that is generally less than two years.

And then Mark, I think you referenced a $250 million maintenance CapEx spend. I just wanted to clarify is that inclusive of JV spending or is that just the net amount to CRC?

It's just net amount.

And then just lastly one housekeeping question if you will, Todd. Just on what looks to be kind of a reduced kind of Q4 guidance. Is that just from some of the timing issues and kind of the two 1,000 a day, if you want to call them interruptions that you guys referenced earlier. That kind of the biggest delta between what you initially kind of outlined as kind of being similar to Q1 after Q4?

Yes, I think it's electrical outages we've been having here in the first month of the quarter. And also we have PFC effects as prices continue to rise. We would have been about 1,000 BOE a day higher when we first put out our guidance for the third quarter versus where it actually came in from just a PSE perspective. So you can see as prices have climbed from here it's going to have more of an effect on our net in Long Beach. And then that also anticipates why our costs free up on our unit basis (inaudible) also.

Pavel Molchanov, Raymond James.

Now that you're at nine rigs and doing a fair amount of activity, are you at a point where some of the longstanding permitting bottlenecks will be begin to kind of become a more meaningful hurdle for you? Or is that still fairly distant?

I think we look and plan our business really on a 12-month basis. And I know on a permitting basis we try to have 180 days of activity built in. Are we always like that? No, but I think we have a pretty handle on it. We have an excellent working relationship with all the state regulators and the federal regulators and everyone we deal with on a local level also. So I think we don't foresee that being a huge issue. There's always issues no matter where you operate in the U.S. with getting permits in a timely manner, but I feel like we have a pretty good process in place to execute on our plan, particularly in Kern County.

And are you approaching a point where unconventionals, whether it's Monterey shale or other acreage might begin to comprise a more meaningful portion of your activity mix? Because I think it's still only, what, 10% of 2017 spend.

Yes, it was a little bit different because it really wasn't the typical unconventional shale that you might think of from elsewhere in the country, but when you talk about like a lower Monterey or something like that, I think when prices start creeping into the 60s, you start thinking about a development or even exploration joint venture kind of science project where you might want to spend some time and effort on that because the size of the prize is so big. But I think as far as big capital program, it's not going to compete today, but I think it's an opportunity to joint venture, particularly probably on the exploration side more than anything in the price environment today.

Gregg Brody, Bank of America Merrill Lynch.

Just on the operational side, maybe you could just walk us through a little bit. I know you gave this fourth quarter realization guidance and in sort of the oil case it looks a little lower than what your third quarter was. And in the case of NGLs and natural gas it's improved. Can you maybe explain why Brent isn't better per se? Or at least it's the same. And then maybe some insight into what's happening with NGLs and natural gas.

As we said, we actually see Brent realizations today higher, but we don't feel like we want to guide anything that's higher than historical average. And if you look at historical average, it's kind of 90 to 95 and 95's in the high end, even though we're above that today. So I think from our perspective we just want to stay within the range of what we historically have seen.

And on the NGL side, I think if you've looked at some of the literature that's been out there, you could see there's potential to go higher, but we see right now that that's improving. As you know, we typically get much better than Mount Belvieu pricing.

And then just on the -- you gave the guidance for the production pits from sort of the PSC as well as the power outage. What's the timing to see the power outage production come back and how should we think about that?

It usually bounces back fairly quickly. It could be anything from three to four hours to 24 hours I think is the longest one we experienced. So again, this all has an impact, but sometimes it has the unintended consequence in areas where you might use ESPs or other downhole devices that have failure when the power goes back on. So that's the unintended consequence that occurs sometimes that it gets you a little bit of a double whammy at the timing on the production and then you have to go back in with the workover rig to bring that back on.

And then just turning to covenants. So there's the timing of this covenant relief is based on a flood insurance getting approvals there. How long do you think that will take?

Greg, this is Mark. It's difficult to say exact timing. The feedback we have from the banks is that it's days to a few weeks. We continue to work closely with our banks to work to accelerate that. So we think it's on the shorter side of that, but we want to make sure adequately (inaudible).

And you noted the $100 million of junior indebtedness flexibility to -- at least to buy back bonds. A couple of questions there. Does that include second liens? And just also part of that, there were also some limitations on dollar prices previously where you couldn't buy bonds back other than the 19s and 20s for less than -- for more than $0.65 (inaudible).

We've not disclosed all the details of the amendment, Greg, but the $100 million that you're talking about allows the company the ability to address the spring maturity situation associated with the unsecured.

And then this is my last question. Ability to exchanges, I don't know if you give anymore color there as to -- I know there were some limitations on that before. Have you created more flexibility there?

I think in my earlier comments I addressed the baskets that we still have in place and we've been working with the banks to in 2015 and 2016 we worked with the banks to put an umbrella amendment in that gave us the ability to contemplate additional deleveraging transactions. That's our style. We've not commented in terms of the exact nature of this amendment and all the things it'll do, but that'll come forth once it's final and executed.

Kalei Akamine, Bank of America.

Production here in 3Q declined modestly and guide for 4Q is still pretty wide. But at the same time you're spending a lot more Q on Q. So I'm just wondering when we can expect to see a clear inflection in production. Any visibility you can provide would be great.

Like I said earlier I think, we've seen the inflection in oil. I think we've seen the bottom or we're kind of flattening out and starting to climb out of that. You've got to remember when you look at the capital some of that is joint venture capital, so it's not like we're getting 100% of the benefit. But as of right now, we think we're at the inflection point of oil production at this point in time.

You've got to remember a lot of this is also matched by the PFC effects. As oil prices continue to climb, our net's going to go down as we need fewer barrels to cover our costs of the production sharing agreement in Wilmington.

And just on the capital for 2017, PRC funded capital has declined this year, which is understandable given the volatility out of the commodity. But just looking at this recovery that we've seen in 4Q I'm wondering if capital spending can come in above what you've guided for here in 4Q. Do you have any (inaudible).

I think if you look at our net CRC investment, the activity set we wanted to pursue with our net investment is still the same, we've just had efficiencies by our operations team on both the OpEx and the CapEx side that have enabled us to come in below. Yes, I think as we see the strength in the commodity typically when you see the curve like it is and you get short-term strength, you're going to ramp up your activity, particularly with workover rigs more than throwing drilling rigs at it, unless you can get some really quick payback items at that point in time.

And last one for me. NGLs were about 72% of PI this quarter. Pretty strong. And I know some of that's probably due to the wide WTI Brent dip. But from your perspective, what's driving that strength and is there anything specific that you can point to?

I think you've got to remember California NGLs, in particular propane, a lot of it's marketed to Mexico. And we have a clear advantage from the other propane that goes to Mexico being mostly from Canada in the Bakken. So we have a transportation advantage. So I think when you look at the NGLs, you'll see typically we're going to have a much higher price than we usually see Belvieu. I think right now as of today we're probably $0.16 over Bellvieu on a gallon basis, but it's fairly normal.

Amer Tiwana, Cowen & Company.

Just a quick question on CapEx. Is there a limitation on your CapEx number under the new agreement?

No, there is not. Other than under the normal financial covenants there's nothing specifically targeting CapEx.

Jacob Gomolinski-Ekel, Morgan Stanley.

Just wanted to follow-up, I think it was on James' question on the GAV. I mean I guess you said that it had originally a two to four year working interest reversion and that was as of a year ago. And given the move in performance and prices, I guess it could be getting pretty close. Do you have a sense maybe just context wise of what that working interest could result in terms of bump in production?

It's fairly significant. Obviously just to give you a for example in the MIRA, they invested 100% of the capital, we get 10% working interest up front. And so when the reversion occurs there, it's going to be sizable. It's going to 70%, 75% at that point in time. So we're going to get from a 10% participation to a 75% participation.

The other one is a little more complicated because it's a different type of measure, it's not a typical joint venture reversion. But that one actually just completely reverts once they hit their threshold rate of return. So it goes from zero to 100% effectively.

So I guess do you have a sense of when you might able to start guiding towards maybe like what the production number looks like in terms of given that might be next 12 to 24 months?

Yes, I think as you'll see prices firm up, if they firmed up in this area you can see us guiding when this might occur, maybe some time late next year or even middle of next year. And we see better visibility on what price and performances -- because we're basically the JV investment started 2Q and 3Q this year, so most oil and gas investments aren't immediate. So they're usually a year or two payback, even in California.

And then when you look at just the adjusted EBITDA number, maybe just a quick modeling question. There's about $8 million of other add backs and then net income and then $11 million noncash items in EBITDA. Can you just speak to what that includes?

Usually the other is related to our power plant and the power that gets sold onto the grid that is not consumed by ourselves. That's usually what that is. And then there's probably some other items, and you can look in when we file the Q to see what all those are, but you're going to about hedging and other mark to market non items, but I think the biggest one typically has to do with the power plant. Mark, is there anything else on that one?

Yes, there's some equity. There's some non-cash equity compensate the (inaudible).

And then sorry, last housekeeping question. Just on the PV10 number, given the bump from year end and also just given the bump from what the slides indicated in Q2. Want to just confirm that that doesn't include sort of surface acreage value or something like your Huntington Beach property when you owned that acreage.

No, it doesn't.

And ladies and gentlemen, that will conclude our question and answer session. I'd like to turn the conference call back over to Todd Stevens for any closing remarks.

Todd Stevens^ Thank you, everyone. Remember, CRC is focused on value. We are optimizing our resource space we're always living within cash flow and dedicated to strengthening our balance sheet to deliver you long-term value for our partners and our investors. These principles will continue to guide us into 2018 and beyond. Any questions, please feel to reach out to myself, the IR staff. Look forward to hearing from you, seeing you out there. Bye.

Ladies and gentlemen, that does conclude today's conference call. We do thank you for attending. You may now disconnect your lines.