California Resources Corp (CRC) 2016 Q3 法說會逐字稿

Hello, and welcome to the California Resources third-quarter 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 over to Scott Espenshade. Please go ahead, sir.

Thank you. I'm Scott Espenshade, Vice President, Investor Relations. Welcome to California Resources Corporation's third quarter 2016 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 CRC's Executive Team.

I'd like to highlight that we have provided slides in our Investor Relations section on our website, www.crc.com. These slides provide additional insight into our operations and third-quarter results 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.

As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of 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-Q, which is being filed today. We would ask that you review it and the cautionary statement in our earnings release.

A replay and a transcript will be made available on our website following today's call, and will be available for at least 30 days following the call.

We have allotted a similar time for earnings Q&A at the end of the 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 thank you, everyone, for attending our earnings call.

I noted early in the year that we believe our long-term success depends on executing on items within our control and acting opportunistically to strengthen our balance sheet as market conditions evolve.

Our team has delivered excellent execution this year on our three key tenets - protecting our base production, defending our margin, and living within cash flow.

Additionally, we have reduced our outstanding debt to a level that is $1.5 billion below our peak, and established a hedge position to protect our capital investment program for 2017.

As I want to emphasize today, we have been focused on looking forward to 2017 and beyond, by building inventory and preparing our organization for the increased activity that we anticipate as oil markets stabilize.

In fact, that increased activity is already beginning, and we now expect our capital investment for this year to reach approximately $75 million to $80 million.

This afternoon I plan to highlight our third-quarter results and the improvement in our balance sheet, and then focus on the value of our business and our forward planning to invest in our resource space and grow our cash flow.

In the third quarter, we delivered solid performance. Our third-quarter production came in at 138,000 barrels of oil equivalent per day, near the high point of our guidance range.

This strong performance reflects the resilience of our asset base and the flattening of our base production decline. It also reflects a lot of hard work by our team to reduce downtime through improved surveillance technique.

We believe our third-quarter production results validate our estimated corporate decline rate, particularly given our greatly reduced capital program.

With the recent stabilization in oil prices, we began to ramp up our activity in the third quarter, adding a drilling rig in each of the San Joaquin and the Los Angeles basins and increasing workover activity.

We began experiencing the positive impact of our increased capital investment toward the end of the third quarter, and expect further benefit in the fourth quarter.

With that background, we expect our total average production on a BOE basis to range between 132,000 and 137,000 BOE per day in the fourth quarter.

Our hedging program continues to support our strategic objectives to protect our cash flows and margin, underpinning our capital program.

Our marketing team works to take advantage of dislocations in the commodity market, with the goal of hedging up to 50% of our crude production. So far we have hedged more than 45% of our estimated fourth quarter 2016 oil production and have nearly 34,000 barrels of net production hedged for 2017.

We will continue to opportunistically increase our hedge positions and seek to reduce our 2017 call exposure as appropriate.

As I mentioned earlier, we continue to focus on defending our margins and posted better than expected production costs on both an absolute and per-barrel basis.

Year to date in 2016, we have reduced our operating cost by 20% from 2015's absolute level. The majority of the cost reductions reflect efficiency gains and lower energy cost.

We are proud of the efforts put forth at all levels of our organization to find and implement cost savings and efficiencies across nearly all of our operation.

Looking forward, the fourth quarter [we'll] close the year blocking and tackling by our operations teams to protect our base production with minimal capital.

Let me turn to our deleveraging progress. As you've seen, we have now reduced our debt by approximately $1.5 billion from the post-spin peak of over $6.7 billion reached in early 2015, at a modest annual incremental and interest cost of approximately $35 million.

During the quarter we issued $1 billion of new secured debt, which we used to pay down a portion of our term loan and revolver. We also completed a successful cash tender for our unsecured bonds at a discount.

As a result, we've reduced the face amount of our debt by a net of $625 million, which Mark will discuss in greater detail.

We believe we executed on optimal deleveraging alternatives, given underlying market condition. These transactions allowed us to reduce our leverage at a modest incremental cost, while preserving other deleveraging alternatives such as asset monetization or potential execution in a higher price environment.

We will continue to evaluate opportunities to strengthen our balance sheet going forward, in light of the long-term effects they may have on CRC and its shareholders.

In the meantime, we will focus on continuing deleveraging through investing operating cash flow and prudent capital allocation.

Let's now focus on the future development of our asset base and growth in our cash flow.

I believe CRC is at or very near an inflection point. Over the course of 2016, our team is focused on refining and enhancing our Life of Field plans, and, as a result, we have nearly doubled our drilling inventory at current strip prices.

We are applying our VCI metric to allocate our drilling and workover capital to our deep inventory of projects.

We also anticipate that our lower cost structure will continue to enhance our cash flow.

We have analyzed several price scenarios near the current strip, and they lead to a stronger balance sheet.

In our base case scenario, which assumes a capital program funded within cash flows and cost containment at mid-cycle prices, we see potential high single-digit multiyear oil production growth and double-digit cash flow growth over the next four years.

These planning scenarios suggest an ability to organically delever and continue to enhance the value of the enterprise.

Given the potential to achieve meaningful deleveraging through operating cash flow, we intend to be thoughtful regarding additional deleveraging transactions, to reach our desired capital structure.

I believe we have the operational flexibility to manage our capital investments within cash flow at flat, current, and strip prices, to reduce our leverage and to be in a position to refinance our remaining outstanding debt maturities in 2019 and 2020.

Our preliminary 2017 capital plans indicate that at modestly higher crude prices, our cash flow would support a higher capital level that, with the endorsement of our bank group, will provide a foundation to further bolster cash flows in 2018 and 2019.

We have planned for multiple capital investment scenarios that range from a minimal base level for mechanical integrity and safety very similar to 2016, up to a mid-cycle level.

We expect to release our 2017 capital investment plan following our Board meeting in February.

In summary, our operational achievement, meaningful deleveraging, and forward planning lead me to believe that we have significantly improved the value of CRC. This is yet to be reflected in our enterprise value, which trades well below our estimated net asset value, and even our estimated reserves value.

At the strip, current valuations barely represent our proved reserve value and do not recognize our additional unproved reserve base, extensive land position, or infrastructure.

We believe our teams have done an excellent job of protecting our base production and increasing our drillable inventory.

We are committed to remaining vigilant as we plan for 2017's increased activity levels, to preserve our cost reduction, to maintain our base, and to extend our exemplary safety record.

We will continue to focus on enhancing our cash flows, optimizing our capital structure, and developing our robust asset base to maximize shareholder value.

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

Thanks, Todd. In the third quarter, we took another large step in reducing outstanding debt, and continued strengthening our balance sheet.

During the quarter, we issued a new five-year, $1 billion secured first lien, second out term loan. We used $250 million of the net proceeds for the new term loan to repay a portion of the existing first lien, first out term loan balance, and $740 million to pay down our revolving credit facility under our bank credit agreement.

We also executed and oversubscribed bond tender offer, which utilized our revolving credit facility to purchase over $1.4 billion of outstanding notes for $750 million.

The net effect, including transaction-related costs reduced debt by approximately $625 million.

I believe the successful placement of the new term loan demonstrates the credit market's acknowledgment of CRC's resiliency through this large and diverse asset base.

Since our spin off as an independent company in 2014, we've evaluated and prioritized prudent deleveraging of our balance sheet. At the end of the third quarter, the cumulative results of our actions, including the effects of operating cash flows reduced total debt by approximately $1.5 billion from its high point in 2015.

Importantly, we accomplished this without selling any significant assets at the low end of the cycle and without significantly burdening the ongoing cash flows of the Company.

The total annual cost of the deleveraging efforts to date is approximately $35 million of interest, and we believe we'll have the opportunity to refinance this as the capital markets normalize.

As Todd mentioned, we can organically deleverage through cash flows and will continue to evaluate alternatives and thoughtfully pursue further deleveraging while being sensitive to the impact on our operations with a focus on enhancing shareholder value.

In anticipation of the bond tender, we amended our bank agreement and also updated our financial covenant. We believe our credit amendment covenants give us sufficient flexibility at current strip prices and cost structure to manage our business through the credit agreement term.

Under the current amendment, our revolver commitments were reduced from $1.6 billion to $1.4 billion.

Just this week, we completed our semiannual borrowing base review. I'm pleased to report that our borrowing base again was confirmed at $2.3 billion. As a result, our available liquidity remained unaffected and stands at over $500 million as of September 30th.

With only minimal capital invested, I believe this serves as a real testament to the resiliency of our asset base.

Continuing with the operational aspects of the quarter, and, as Todd mentioned, in August we reactivated our drilling program by deploying one rig in the San Joaquin basin, focused on steamfloods and waterfloods, and another rig in the Los Angeles basin at the Wilmington field, working on a half-time basis.

We drilled and completed 21 wells. As we noted in our last call, we also steadily increased our workover activity in the third quarter.

The increased drilling and capital workover activity resulted in capital investments of $19 million for the quarter, which was in line with our guidance.

This represents a change from the first half of the year, which saw negligible capital for drilling completions and workover activity.

As Todd mentioned, we believe CRC's approaching an inflection point. At current commodity price levels, we expect to continue increasing capital activity in the fourth quarter of 2016, and, as a result, increasing full-year capital investments to approximately $75 million to $80 million, well within our expected cash flow for the year.

Production volumes for the third quarter came in toward the high end of our guidance at 138,000 barrels of oil equivalent per day. This was just 1% lower than the prior quarter and 13% lower on a year-over-year basis.

The negative PSC effects on the third quarter 2016 production were offset by production which was deferred into the third quarter due to third-party pipeline disruptions.

I'd like to point out that we held oil production steady with the second quarter at 90,000 barrels per day, which represented a 13% decline from the prior-year quarter.

NGL production for the third quarter of 2016 was also flat with the prior quarter, and at 16,000 barrels per day and 11% lower than the third quarter of 2015.

Natural gas production averaged 193 million cubic feet per day for the third quarter, compared to 202 million cubic feet per day for the previous quarter, and 226 million cubic feet per day for the year-over-year period.

Our third-quarter realized crude price of $43.03 per barrel, including cash hedges, was $0.67 per barrel lower than the prior quarter due to fewer barrels hedged at $4.76 per barrel lower than the third quarter of 2015.

Our hedges increased our realized price by $1.30 per barrel during the third quarter, compared with $2.29 in the prior quarter.

We expect realizations in California to continue to improve going forward, as prices strengthen along the trend of the forward strip, with support from the new availability of export markets and the entry of new downstream players.

Our third-quarter NGL realized price of $22.45 per barrel was in line with our second quarter of 2016 prices, and roughly 33% higher than the third quarter of 2015.

Natural gas prices followed typical seasonal patterns, with our third-quarter realized price of $2.64, reflecting a 59% increase over the second quarter of the year.

In addition to seasonal factors, continued disruptions in California natural gas storage are strengthening gas differentials as we move into the winter.

Compared to last year's third quarter, our natural gas prices were down almost 7%.

As we highlighted last quarter, we targeted some workover activity in the Sacramento basin to take advantage of the higher gas [price].

Increasing levels of workover and down hole maintenance activity, combined with higher gas and seasonal energy prices resulted in higher production costs for the third quarter compared to the prior quarter.

Production costs due to higher natural gas prices are more than offset by the revenue increase from our natural gas production.

Third-quarter production costs came in slightly lower than our guidance, at $211 million or $16.63 per BOE. This was modestly higher than the $188 million in the second quarter of the year.

Third-quarter costs were 14% lower than levels in the third quarter of 2015 on an absolute basis, demonstrating the continued efficiencies being delivered in our operation.

Cost containment also continued in other aspects of our business, in addition to lower production cost.

Third-quarter adjusted general and administrative expenses were flat with the prior quarter, and $10 million lower on a year-over-year basis, reflecting continued employee and contract cost reduction initiative.

Exploration expenses of $3 million were $2 million lower than both the prior sequential quarter and the previous-year quarter.

Taxes other than on income were $5 million lower due to this year's tax reassessment, and we should see similar levels over the next three quarters.

DD&A expense in the third quarter was significantly lower than 2015, due to the 2015 impairment charge and its effect on current year DD&A rate.

Interest expense of $95 million included the $12 million nonrecurring deferred cost write-offs related to the tender offer, and reflected a $6 million sequential quarter net increase in interest expense related to the new term loan, partially offset by the impact of retired note.

Excluding these tender offer-related transactions, third-quarter interest expense was within our guidance range.

During the third quarter of 2016, we reported net income of $546 million or $13.06 per diluted share. This compares to a net loss of $140 million or $3.51 per diluted share in the second quarter, and a net loss of $104 million or $2.72 per diluted share in the prior-year period.

The bond tender resulted in a net gain of $660 million. The adjusted net loss of $71 million or $1.75 per diluted share, excludes this gain and other smaller items. This compared to an adjusted net loss of $72 million or $1.80 per diluted share for the second quarter of 2016, and adjusted net loss of $86 million or $2.25 per diluted share for the third quarter of 2015.

Adjusted EBITDAX for the quarter was $164 million, compared to $160 million in the prior quarter, and $212 million on a year-over-year basis.

These results reflect our ability to maintain margins and cost containment, as well as opportunistically place hedges to minimize price impact.

Operating cash flow for the current quarter was $101 million. We generated $88 million of free cash flow after working capital, demonstrating our ability to live within our mean.

Please note that we've provided key fourth quarter 2016 guidance information in the attachments to our earnings release. And I'll be happy to take any questions you may have on that information [or] other aspects during the Q&A portion of the call.

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

Thank you, Mark. As I wrap up, CRC's third quarter of 2016 was again characterized by focus execution, flattening declines, cost reductions, and continued deleveraging.

Our management and operating teams have extensive experience with these assets in all phases of the commodity cycle, which helps us control costs, thereby enhancing margins and growing the overall value of CRC.

The focus on our Life of Field plans has doubled our actual inventory at today's price level. We believe that investing in these opportunities will meaningfully increase our net asset value and, ultimately, our corporate valuation.

Over the past year, as Mark and I have described, we've taken several actions to strengthen our balance sheet. Continued focus on execution of our plans will allow us to increase production, control cost, and grow our margin.

As a result, we expect to continue deleveraging organically through increasing cash flow.

As market fundamentals change, we will look for additional opportunities to delever, which will focus on enhancing shareholder value.

We believe we have sufficient flexibility to increase our activity levels, achieve our target leverage goal, and maximize shareholder value over the long term.

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

Thank you. We will now begin the question-and-answer session. (Operator Instructions) At this time we'll pause to assemble the roster. Evan Calio with Morgan Stanley.

Just want to understand the capital allocation between debt pay down and the move to maintenance capital, CapEx level of $400 million to $500 million.

What is the first call on capital? I mean, is it holding production flat within cash flow the first call, and then when you reach that maintenance level, does it invert to debt pay down? Or help e with the interplay.

Evan, thanks for the question. It really is the same value proposition as we allocate capital. We're looking to allocate capital, whether it be to financial instruments and paying down debt, if we have that opportunity, if our debt's trading at a discount, we have to evaluate that versus investing in our inventory and the value proposition for our shareholders.

So I think we would look based on what we know today. And where our debt's trading today, I think you would think that we would invest in our inventory first, and, as that comes up to a level which we might think about being maintenance capital holding flat, then you might look at where our debt's trading again and look to continue to pay down debt.

But I think at this point in time, the value proposition's greatest by reinvesting in the business.

And maybe a follow-up to that. I know you guys completed two debt-for-equity swaps this year for about $118 million, able to retire debt at discount to face.

I mean, how should we think about that strategy going forward? Is that something that we should expect more of or was that merely opportunistic?

Like we outlined, we're going to be opportunistic. And depending of the circumstances at that time, we're going to be very cautious about dilution or issuing shares.

This is something we take very seriously. Myself personally, most of my net worth is tied up in CRC, and I would say that's probably true for almost all the management team. And we have an enormous employee stock purchase plan.

So we all take this very seriously. We think about incremental, what makes the most sense from a value proposition for our shareholders longer term. And at that time, we felt that that was something that made sense on an incremental basis.

Maybe lastly, if I could, the oil volumes appear to be inflecting now in a CapEx that's well below $400 million.

I mean, any update for us on a maintenance capital level? Is it now below $400 million?

I think I can definitively say it's below $400 million and probably closer to $300 million. But also, you're trying to talk about moving mix of oil, what you're trying to hold flat, natural gas BOEs, all those things.

So I think when you talk about holding oil flat, it's probably closer to $300 million than $400 million.

Good stuff. Thanks, guys.

Doug Leggate with Bank of America.

So, Todd, I know we've talked about this, this topic once or twice in the past. But let me do this in bullet-point form.

In your prepared remarks, you acknowledged that you've got an enormous asset base. I think you have said in your lifetime, you're not going to get to drill that.

And the problem you've got right now, as I see it, is that your interest charge, even though you've paid down the face value of debt, your interest charges are still a big burden on your cash flow.

Pretty simply, you don't have the cash to reinvest at a quick enough rate.

Why wouldn't you sell assets to bring forward drilling activity, given that formula that I've just laid out?

Yes, I think, Doug, as we tried to outline, you look at the forward curve going forward, we have the ability to organically delever the Company, looking at the strip or anything close to the strip at this point in time.

So we're not holding any fire sale. And I think that's really the issue. If we get valuation -- and we have sold some, I'll say modest assets here and there, nothing that's material.

But if we get the valuation that makes sense and it's accretive, we're going to pull the trigger on those transactions.

And the great part about the deleveraging we accomplish as we outlined, was we didn't really give up any meaningful EBITDA like we might have in a traditional asset monetization.

Let's say we sold something at 10 times, and it was $150 million. We still have all those alternatives available to us going forward, and we were able to capture the [debt] discount for a very modest carry in our interest charge.

So I think for us, it's really just doing the right thing and being patient. I mean, we could jump on opportunities. But again, we're not looking to hold a fire sale and just do a deal to do a deal. I think what we're trying to do is the thing that makes sense for our shareholders over the long term.

No, I don't want to labor the point. I understand your point on EBITDA. But cash is a real cost. Interest is a real cost.

When you're spending $75 million and your interest charge is just increased on an annualized basis by north of 50, that's real money out the door.

So I'm trying to understand why wouldn't you a bite the bullet on, not fire sale necessarily, but stuff that has no value to you because you're simply not going to drill it any time soon, and used that [cash charge]?

Yes, I don't think you're capturing everything, because I think it's about 35, 36 is the incremental charge.

Even so, so it's half your CapEx budget.

For this year, yes. I mean, obviously, we're in a different type of year this year as we come into the year when the product prices were in a free fall. So we shut down all activity, except for basic maintenance of our power plant and basic mechanical integrity early in the year.

We didn't really start stepping up working capital -- I'm sorry -- workover rigs and drilling rigs until the back half of the year.

Yes. You don't need me to tell you. I guess showing growth (inaudible) you're going to get paid for that (inaudible) space, as you well know.

My last one, Todd, if I may, is going to the inflection point. So the nature of steamfloods and waterfloods is a little bit longer dated, obviously.

So once you put capital back to work, should we think of that activity as more of the workover cash OpEx level or are you thinking the inflection coming from actual drilling activity? And I'll leave it there. Thanks.

I think it's actual drilling activity. As we've discussed internally is, it's nice to get back in the business of investing in the business. And I don't really consider, even though it does add incremental rate and sometimes reserves when you talk about some of the activities you do that get captured us OpEx, real investing in the business is drilling wells and doing capital workovers. And so that's what we consider getting back into the investing business and the inflection point.

Thanks, Todd. I appreciate you taking my questions. And I guess I'll see you in a couple weeks. Thanks.

Paul Sankey with Wolfe Research.

Just following on from that, you said, I think, you're adding two rigs. Can you talk a little bit more about where you need to take those rigs?

It looks like your volume's beginning to flatten, at least sequentially. And I wonder what kind of activity, also thinking about what Doug just said about a relatively potentially slower reaction to the nature of your activities, what kind of level of rigs do you need to get back to in order to maintain that flat -- it seems like you're now targeting flat volumes, as far as I can make out, and hoping for the oil prices. Is that fair? And how many do you need to do [that]?

No, I think we're going to live with our basic tenet of living within cash flow.

And I think if you look at the planning scenarios for potential product prices next year, obviously, you could think dire things and go back to a mechanical integrity-type spending, or you can talk about spending money on investing in the business and ultimately growing the business.

So for us, right now we have basically a half rig working down in the Wilmington field, and we have one rig working up in the San Joaquin basin.

And I think if we talk about next year and a little bit more increased activity, that activity, the increase in drilling activity, will probably be in the San Joaquin.

And it probably doesn't take many rigs to hold oil production flat, if you thought about it from that perspective, next year.

I thought you just said we should think about 300 million bucks. Is that what you said --

Yes, I think --

-- of spending?

-- what we're thinking about from a planning standpoint, if you look at the curve and taking a standard deviation north and south of where the curve is, you know you're probably talking about mechanical integrity on one end and maybe $500 million on the other end.

So that's the range of scenarios we're looking at. But that's what if you've [looked] in the middle of that, that could be where it might land up, when you look at the current strip.

Because, again, the basic tenet, manage within cash flow, and we're fortunate to have the high level of operating and control and being able to do so.

Yes. Just on the hedging program, I think I understand what you've done. But you set out a [store] for 50% of production to be hedged. And then it seems like you sold calls, basically, with, I guess an assumption that down the line you're going to be putting puts on? Or am I looking at that all wrong?

No. Actually those calls --

I'm really talking about 2018.

Yes. Those calls were actually matched up with puts from the first part of 2016. So in the first part of 2016, we bought puts and sold calls for 2017 and 2018.

So our goal would be over time to lessen our exposure to those calls in 2017 and 2018. If you have tracked our 2017 calls, you'd see that we've lessened that exposure when you get the kind of macroeconomic events that cause the disjointed trading in the market. And we've done that.

And as we continue to layer in the floor or the hedges in place that we need to protect cash flows in our capital program.

Yes. And is there kind of -- it looks visually like it's got to be around at least 48 bucks to the downside for you to want to do these puts. Is that a fair assumption? And is that kind of the meaningful number for you guys in terms of standing still and not deteriorating the balance sheet?

[As you] think from the standpoint of we feel comfortable with where the price is and locking it in, we do like some of those process.

As far as feeling comfortable investing capital, price is lower from here. I think as long as it has a [four handle] in front of it, we feel fairly comfortable investing money for the long term into our inventory.

But we've layered some hedges on as it's traded up and down with volatility this year, anywhere from $48 up into the mid-50s. So there's a lot of hedges. And it's not like we've layered on a lot of 10,000 barrel a day hedges. It's a lot of 1,000, 2,000s in there. That's the average.

Yes, okay. All right. I think the other one I'll leave it. It was about disposals, but I think you've kind of tried to address that. And I'll leave it right there. Thank you.

Thank you. Pavel Molchanov with Raymond James.

This is Luana Siegfried. Quick question about the covenant [thing], and if you could update us on the current covenant that you have for the next quarters.

And I ask this because last February, for this quarter, EBITDA covenant was up around $190 million and adjusted EBITDA for this quarter was $164 million.

So I'm not sure if there is any update on this topic. Thank you.

This is Mark. I think it's important to recognize that in the fifth amendment, we modified our covenants and that that one covenant that you talked about was relaxed or eliminated.

As we run our pricing sensitivities and our planning scenarios that Todd referred to, I think it's important to note that we see ourselves in compliance with covenants as we move through 2017, down into the low 40s.

So as I said in our remarks, we believe that we've got runway through 2017 into 2018, at current forward strip and got plenty of room, plenty liquidity.

Perfect. Thank you, Mark.

Thank you. James Spicer with Wells Fargo.

Can you remind us what level of CapEx is allowed under your credit agreement? I think it's $200 million for 2017, plus you have some carryover for this year, and then there's room for an increase. Can you just walk through that a little bit?

Yes. Just so you know, that we have what was allowed this year, what's allowed next year, and then there's a carryover effect and then there's also an increase in the back half of next year. And I'll let Mark walk you through that.

Sure. We've got limitation of $125 million in capital investment this year, but we can carry over amounts into 2017. And we've got a base of $200 million in 2017. And then, as Todd indicated, can potentially ramp up another $50 million in 2017.

So we can carry over anything we don't use in 2016. That's additive to the $200 million. Then we can take it up another potential $50 million, based on conditions we see in the latter portion of the year.

So when you add that all up, it's $300 million, plus or minus, without going back to the banks.

But as Mark would tell you, we've maintained an outstanding relationship with the banks. You don't get five amendments from the banks over the last two years, without that -- and the way we've managed the business and how prudent we've been with our cash flow, I think that if we went to them with a plan and prices were at a level where we could manage within cash flow, I don't think it will be an issue to raise the capital investment profile of the Company.

Okay. Yes, that was really my question. Would you really even have the ability to get to that level of CapEx where you could hold production flat and grow production.

And that kind of gets to my second question, which is you laid out a scenario in your prepared remarks, Todd, around single-digit oil production growth and double-digit cash flow growth.

Can you just clarify what you're assuming there in terms of pricing and CapEx again?

Yes. So if you look at, we would be assuming, basically, the different scenarios. As you look at the curve that we have out there, the forward curve for oil, you make a flat assumption on natural gas prices, and then you do basically a standard deviation up and down from that, and you go forward, you can see real easily scenarios where you're going to get middle to single-digit, high single-digit oil production growth and you're going to get probably somewhere plus or minus 25% cash flow growth.

Okay. That's helpful.

James, just to clarify, that's all within cash flow.

Yes, understand. Okay. And then one more, if I can. You talk about your organic deleveraging process. As you look at your numbers here at strip, you're still close to six times in 2019.

Just wondering what your real target is in terms of deleveraging and if the pace of deleveraging is sufficient on an organic basis to really get you to where you want to go? Or is it the case that I know you want to be opportunistic, but is it the case that you're going to eventually have to look at other alternatives?

If the strip holds true, we can organically get longer term below -- get to three is Mark and my goal. But I think we get to three and a half or so, under our current scenario planning, depending on what you believe price and what you forecast price out at.

Obviously we're going to be opportunistic. We're blessed with a great set of assets beyond our traditional subsurface E&P assets.

So we will look at things. And we think as our counter party risk improves in some people's eyes, that some of those transactions will go from perceived fire sales to more appropriate levels of return.

And then I think those opportunities will present themselves and we'll be able to accelerate, as Doug talked about, getting the balance sheet squared away to get the cash flows to reinvest in the business.

Yes. Okay. Thank you very much.

Thank you. John Herrlin with Societe Generale.

In terms of your fourth quarter activity increase, will it be kind of proportionate to what you were doing in the third quarter, meaning mainly San Joaquin and then a lesser amount in Wilmington? What are you doing?

That's exactly right, John. It'll be very similar to third quarter. And there's, remember also, as we've outlined, there's some workover activity going on in the Sac basin also.

Okay. All right. That's all I wanted. Thank you.

Sean Sneeden with Oppenheimer.

Todd, maybe can you talk a little bit about the payback on some of the projects you're talking about spending on for next year?

And specifically what I'm thinking about is or what I'm wondering about is how we should be thinking about production profile as we go along here.

Should we be thinking about a little bit of a dip before some of your increased spending (inaudible) up to get it to take hold?

Yes. So if you think about all the levers we can pull next year, but as we've looked at kind of a base case scenario, we believe we're going to be at a point, like we said, an inflection point where we're starting to invest in the business and start holding it flat and starting -- so obviously, that inflection point occurs at some point in one quarter and then you start growing again, the business, going forward.

And I think all these projects we're talking about that we potentially invest in next year, are going to have less than two-year payback-type projects at the current strip. So we feel really good about these investments for our capital.

Okay. That's helpful. And maybe just kind of thinking about that in another way, but as you scale back up to, let's just say like the maintenance capital you've laid out, how long is it or how should we think about the lag between spending capital and seeing the production response?

It just depends on what it is. I mean, if you're talking about a greenfield steamflood, which, but we don't have any of those, that would be a longer-term response. But you're doing work in the steamflood, you're going to get quicker response in [months].

Or in some cases if you're doing workovers in the Sac basin, you're going to get an immediate response.

So it just depends. We have such a diverse portfolio, that you're going to have all kinds of responses. But I'll say most of them are within the first month or two.

Okay. That's helpful. And then on your $300 million of maintenance capital to hold oil volumes flat, is that just a D&C number or does that also include facilities?

That's an all-in number. And I said, yes, I said, it's closer to $300 million than $400 million, to hold production flat.

But again, any single year, as I've told you before, as you've seen in prior years, with a modest amount of capital, we can pull levers to keep production flat in that year, at pretty small numbers or pretty big numbers.

But it's really just what impacts does that have on the subsequent years. And that's really our concern is, we're talking about multiyear projects. We're not just trying to hold production flat for one year. We want to flatten it out and then grow it.

And as Doug said, you need to be in the business of growing the business, and we understand that as well as anyone.

No, I think that makes sense. And then just one quick last one, if you don't mind. The three or three and a half 2 times leverage number I think you threw out on the previous question, was that a 2017 number or is that just your longer-term target?

It's our longer-term target that Mark and I have said from day one.

Okay.

We would prefer to be slightly below three, but it's good to have aspiration.

Fair enough. I appreciate it, guys. Thank you.

Thank you. Jacob Gomolinski with Morgan Stanley.

Just had a quick question on I saw you were taking CapEx up in the fourth quarter. At $46 Brent, what kind of IRRs are you getting on that CapEx?

Well, we allocate our capital internally on our VCI metric, which is a DPI metric. So, I mean, obviously, a byproduct of that as you look to allocate capital, you're going to look at payback and other things. But we really don't straight allocate these on just an IRR-type return.

Okay. I guess then --

These projects all have in excess of two VCI, just to give you a feel for it.

Okay. That's helpful. Thanks.

And then remind me, I guess I'm forgetting, what is the capacity for bond buyback remaining?

I'll let Mark go ahead. But, yes, there's limitations. But we can do that depending on what we -- asset sales and the like.

Yes, we've commented before we had roughly $900 million of capacity left under some of the initial [baskets] with our initial unsecured notes. We think there's some -- that's the technical level we had.

From a practical perspective, we think there are some limitations on what we may be able to pull the trigger on just [the] difficulty or challenges with waivers and amendments.

But we, as Todd says, we continue to look at all options to delever.

Okay. So that just the, I guess practical limitations aside, the technical limitation is $900 million for buyback is the -- ?

Yes, roughly.

But if we were to monetize, let's say our power plant, a midstream asset of some kind, or a non-borrowing base asset, which could be some E&P assets that aren't in the borrowing base, 60% of those proceeds go to pay down the bank and 40% can be used to purchase our debt back in the market.

Okay. And then one last question, if I may. On the last slide, for the facilities and midstream assets, where it says the discount is estimated to exceed the burden on the reserves of the incurred assets, could you just help me understand how that works, how if you were to sell those assets, it wouldn't impact the reserves by an equal amount?

Yes. So if you thought about how if you didn't have all these assets and you had wanted to replicate them, I think on the low end, you're talking about two bucks a barrel. And if you were gold plating it like some of our competitors do, it might be four bucks a barrel.

So I think that that would be the approximate range you would want to work with.

So as you know, our power plant, a third of that power, approximately a third, is being used by ourselves, and the rest is sold on the grid. So there are some assets there that the full value is outside what might be in the borrowing base.

Just to add to what Todd's saying, we believe or we've triangulated in from a couple different fronts. We believe the value of our aggregate midstream assets is a multiple of what we've described here.

And so we expect -- what we're trying to say in that is we, in affect, reduced that value for the effects that Todd described.

Right. So you reduced it by enough where if it were to be -- that value were to kind of go away through a sale, it wouldn't affect the value of the reserves remaining?

That's correct.

Correct.

Okay. That's really helpful. So two to four bucks a barrel, and that -- that's great. Thank you very much.

Thank you. And as there are no more questions, I would like to return the call to Management for any closing comment.

Thank you, everyone. If you have any questions, please contact Scott or ourselves here in Los Angeles.

Thank you. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.