California Resources Corp (CRC) 2015 Q3 法說會逐字稿

Good afternoon, and welcome to the California Resources third quarter 2015 earnings conference call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. (Operator Instructions). Please note that this event is being recorded. I would now like to turn the conference over to Scott Espenshade, Vice President of Investor Relations. Please go ahead, sir.

Thank you. I'm Scott Espenshade, Vice President of Investor Relations. Welcome to California Resources Corporation's third quarter 2015 conference call. Participating on today's call is Todd Stevens, President and Chief Executive Officer of CRC, and Mark Smith, Senior Executive Vice President and Chief Financial Officer. Also there are several members of CRC's executive team present. I would 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. 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 the Federal Securities laws, these statements are subject to risks and uncertainties, and that may cause actual results to differ from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available in the Company's 10-K. We ask that you review it and the cautionary statement in our earnings release. We've allotted approximately 30 minutes for our Q&A at the end of the call. We ask participants to limit their questions to a primary question and a follow-up. I will now turn the call over to Todd.

Thank you Scott. Thank you everyone for attending our earnings call. I am extremely proud of the way our team continues to respond to the challenging and volatile price environment, as we have met or exceeded all of our controllable targets. We recently held an Analyst Day and hosted site tours of our Elk Hills and Wilmington Field. There we reiterated our strategic goals and showcased our world class assets and the depth of our inventory. The feedback has been very positive. And the participants who were able to see firsthand the breadth of our mid-stream assets, and the overall scale, scope, and feature of the potential of our vast upstream portfolio.

We continue to execute on our value-focused strategy, and carry out and accomplish our 2015 operational objectives. CRC has shown its ability to execute on all aspects of the business over which we have control. Again in the third quarter, we generated positive free cash flow, even in the midst of renewed weakness in commodity prices. This enabled us to reduce our debt by slightly more than $100 million compared to the prior quarter end. I want to emphasize we're delivering on our free cash flow pledge, while many in our industry are just finding this religion. Our team kept our oil production flat with the prior quarter, and overall production was at the high end of our guidance range. Our year-to-date crude oil production increase was accomplished with only 20% of the capital investment that was incurred in 2014. Reflecting a more value focused approach and capital allocation strategy.

Further, we have been running below our planned level of $440 million so far this year. Largely as a result of efficiencies we have implemented across all aspects of our business. We believe we will end the year with a lower than announced capital level, while drilling more wells than we had originally planned and delivering higher production than we originally envisioned. Our production costs also came in below our expectations for the third quarter, on a gross dollar as well as a per-unit basis. The operating costs and capital reductions we've experienced during the year have largely been the result of our team's unwavering focus on generating efficiencies throughout the Company. We believe the majority of these reductions to date are process oriented and sustainable, and the remainder tend to be deflationary.

While second quarter oil prices rebounded slightly from first quarter levels, in the third quarter prices deteriorated again, basically back to first quarter levels. We're continuing to respond to lower prices by focusing on the fundamentals of our business. Protecting our base production and defending our margins. We're succeeding on both fronts. At the same time we are focusing on building a development and exploration pipeline of inventory, that we can implement in the current environment, and even larger backlog when prices recover. We feel strongly that our capital efficient portfolio is very competitive in a lower for longer price environment. We believe that we can maintain essentially flat oil production beyond the next three years with capital between $600 million and $700 million annually.

I would like to expand on that last point. Our ability to achieve this begins with our best-in-class base decline rate of 15% historically, which includes downtime. We do work to maintain our base production and minimize downtime, which adds some of the most valuable barrels to our production, as we work towards our engineered base decline of 10%. We believe we will continue to bring down our decline rate through more efficient capital allocation using rigorous life of field planning, as well as through better equipment failure prevention, as we showed on the Analyst Day tour. The moderation of the Elk Hills field decline rate, as it continues to move from primary to secondary recovery, will further add to the moderation of our base decline. As we have noted since our spin, one of the major items we have changed has been our capital allocation process. We utilized our Value Creation Index, or VCI metric, to maximize shareholder value for the Company over the long run. It encompasses many of the financial tenets that we believe drive value over the long-term, and measures the bang for our buck of every dollar invested.

In our earnings slide deck on slide 8, we show how we build value in our deep inventory. This is a high-graded inventory that's met our investment hurdle of a 1.3 VCI, but this is by no means all of our inventory. For example, the next slide shows the greater Elk Hills area, where we have significantly more inventory in excess of 10% cost to capital rate, even at today's prices, or a VCI of 1.0. We want to build value and look to improve the economics of our inventory. Our technical team is focused on refining their estimates and procedures over time, to bring more opportunities for investment that meet a 1.3 VCI hurdle. In the current environment, we are targeting higher margins, high return, and low decline oil projects. We emphasized this in our 2015 investment plan, but it is important to remember we look at our investments using VCI rankings on a full-cycle basis.

In our 2015 capital plan, we break out our capital investment by activity and drive mechanism. It's also important to note that our current-year plan included only $200 million of drilling and completion, plus workover capital to maintain this flat production profile this year. But what about the future? Just like our investors, we manage a portfolio of investment opportunities. We have the flexibility to allocate capital of different drive mechanisms, and to change the activity level to meet our objectives, which is to create value for our shareholders, live within cash flow, and provide growth in a normalized commodity price environment.

The previously mentioned slide provides a static look at this inventory as of today, but we are focused on increasing this executable inventory over time. We plan to accomplish this increase by derisking our exploration set, reducing development costs, and applying technologies such as our unparalleled 3D seismic database to further refine and execute or life of field plan. Although we are currently allocating very little capital to our exploration program, we have still seen notable success on these efforts. As we stated last quarter, and more recently at our Analyst Day last month, we have a deep portfolio of both conventional and unconventional opportunities. This is highlighted by a recent successful exploration well that we talked about, which has continued to produce in excess of 400 Boe per day, this well is still naturally flowing from a conventional reservoir, that has further behind pipe, uphole potential, as well as additional offset opportunities.

We continue to focus significant attention on all opportunities to delever our balance sheet. Our diverse asset base, including both our integrated infrastructure and our significant upstream operations, has attracted significant interest from numerous potential investors. At this point we have narrowed down the opportunities to a handful. We've been very diligent and reflective in our approach to execute transactions that we believe will maximize long-term value to our shareholders, as opposed to rushing into any particular transaction. This inevitably has led to a longer process, we are exchanging term sheets, and in some cases drafts of definitive documents with these parties, and hope to announce at least one transaction by year-end. Our top goal remains to eliminate approximately $1.6 billion of debt by the end of 2016. Mark will address our credit facility in greater detail in his remarks, as well as the recent bank amendment and the added flexibility it provides.

As I previously mentioned, not only has our debt level stabilized, it has actually declined slightly in the third quarter. We expect to continue to operate within our cash flow in the fourth quarter, and maintain our net debt level comparable to the third quarter, before the effect of any deleveraging transaction. In the third quarter, we achieved positive free cash flow. After adjusting for the effects in early 2015 of paying off the much higher payables left over from 2014, we expect to have positive free cash flow for all of 2015. Even in this highly volatile price environment, we continue to demonstrate our ability to live within our means, another key differentiator for CRC.

Our third quarter capital investment amount was slightly below our guidance range. Maintaining a capital program that invests within available cash flows will remain a key tenet of our strategy in 2016 and beyond. We continue to focus on reducing our overall cost structure. In the third quarter production costs and adjusted G&A expenses were lower than our expectations, on both a gross dollar and a per-unit basis. And in line with these cost-cutting efforts, we felt it was prudent in this current extended low price environment, so suspend our dividend of $0.01 per share per quarter beginning immediately. This equates to a savings of almost $16 million on an annual basis, or approximately $0.30 per Boe. We will reexamine this decision as prices normalize.

As we have said before, we believe cutting costs, and aligning the Company's size and structure with market conditions, is essential to defending our cash margins in this highly volatile price environment. We have now been an independent company for 11 months. When we began the process of spinning off in 2014, we certainly didn't expect to be facing the type of oil pricing environment that hit us straight out of the gate, and continued to deteriorate during the past year. As a result, we have taken decisive steps to operate more efficiently, and bring our cost structure in line with a longer term, more moderate price environment. At the time of the spin-off, we had about 2,000 employees. To align our workforce with our normalized view of commodity prices, we will end the year with about 1,700 employees, a 15% reduction. We achieved this reduction primarily through attrition and our third quarter voluntarily retirement program, along with limited layoffs. Mark will touch on the specifics and the impact on the quarter later in the call. It is important to note that we do not expect these actions to impact our production outlook. They will, however, reduce our production costs and G&A starting in the fourth quarter, and enhance our margins. Our third quarter production was at the high end of our guidance range. Highlighting the strength of our assets. We continue to be pleased with the results of our overall production, in particular the manner in which oil production is holding up with much lower capital levels. As we continually emphasize protecting the base, I'd like to point out that our base production continues to perform better than our overall anticipated decline of 15%.

Additionally, we continue to shift our focus to more oil-weighted production profile. As we've said, the 2015 capital plan is almost entirely focused on oil production, mostly steam floods and water floods. We believe the low capital intensity of these recovery methods will allow us to deliver higher oil as well as total production in 2015 compared to 2014, in spite of some fourth quarter unscheduled downtime, and regional power outages due to severe weather that we experienced across California. The diversity of our asset portfolio and our capital allocation process, allows us to deliver high value production and provide operational flexibility throughout the price cycle. We are currently focused on low-risk, low-capital intensity, oil directed development, while prices remain depressed. In addition, we have a large inventory of conventional development projects that are expected to be repeatable with low technical risk. We have over 130 fields with multiple pay zones, which gives us a sizable multi-year development inventory. We are currently deferring many of our higher value projects until prices rise and provide additional cash flow, as we adhere to our commitment of living within our means.

We've also spent a large part of this year hydrating our projects, and improving their economics, by redeploying some of our best engineers and geologists, to devise more efficient and effective ways to develop them. As a result, we are continuing to increase our inventory of projects that can deliver life of field VCI of at least 1.3 in a variety of price environments. This life of field approach will continue to keep us focused on maximizing shareholder value through effective capital allocation.

As we look toward 2016, we again expect to demonstrate our primary financial tenet, keeping our investment capital within expected cash flow. We are in the process of developing our dynamic capital plan for 2016, which we'll be able to adjust quickly in response to commodity price changes. In addition, we believe we'll be able to supplement our organic capital program in 2016, with joint venture opportunities with strategic partners to co-develop certain of our projects. We also believe we will be able to maintain a capital program in 2016, that will hold our oil production essentially flat, assuming that the current market conditions persist. We plan to announce our 2016 capital plan in February, following our Board meeting. 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 showed higher oil production and lower costs in all categories compared to the prior year. We continue to live within our means and generated positive free cash flow, while keeping our oil production essentially flat with the second quarter of 2015. Interest expense was higher year-over-year as a result of the debt we incurred in the fourth quarter of 2014, associated with the spinoff. Results as expected were affected by lower product prices. We again meet or exceeded all guidance categories for the quarter. We came in at the high end of our production guidance, and at or below guidance ranges for costs.

Now looking more closely at the specifics, crude oil prices in the third quarter were lower than second quarter 2015 prices. The Brent index average for the third quarter was $51.17, or 19% below the second quarter of 2015 average price of $63.50. Our realized oil price followed the Brent decline, averaging $47.79 per barrel, including the effects of realized hedges for the third quarter. A 16% decline compared with the average second quarter price of $56.73. Our hedges contributed $1.69 per barrel to our realized oil price, our crude oil realizations for the third quarter were 90% of Brent, before hedges or 1 percentage point higher than the sequential quarter at 93% of Brent after the effective hedges.

NGL realizations followed lower crude oil prices with third quarter prices averaging $16.92 per barrel, down 17% from $20.47 in the second quarter. However, our realized natural gas prices were 14% higher in the third quarter, averaging $2.83 per Mcf, compared with second quarter prices of $2.49 per Mcf. Our natural gas hedges contributed $0.03 toward the realized price in the third quarter. The NYMEX natural gas index was essentially flat for the two quarters, while our realizations improved by 11%. Improvement in the realizations was largely the result of the impact of summer demand on California natural gas prices.

As in the previous quarter, on a year-over-year basis, all third quarter average commodity prices were significantly lower. Realized crude oil prices both with and without the hedge impact were down approximately 50% from $96.27 per barrel, NGL prices were down 64% from $47.20 per barrel, and natural gas prices were down 33% from $4.24 per Mcf. Against the backdrop of the continued weakness in commodity prices, we're very pleased with our crude oil production, as well as total production results for the quarter. Again this is a testament to our stable, low-decline asset base.

The third quarter 2015 crude oil production averaged 103,000 barrels per day, now this represents a 3,000 per barrel per day, or 3% increase on a year-over-year basis. Sequentially third quarter oil production only declined 1,000 barrels per day, or 1%. Third quarter 2015 NGL production was essentially flat, compared with both year-over-year and sequential quarters. Our third quarter 2015 natural gas production declined 23 million cubic feet per day, or 9% from prior year levels, and declined 8 million cubic feet per day, or 3% sequentially. As we stated previously, this gas production decrease was expected, as we were focusing our drilling programs entirely on oil. For the third quarter of 2015, total production was 158,000 barrels of oil equivalent per day, compared with 160,000 Boe per day in the prior-year period, and 161,000 Boe per day in the second quarter of 2015.

Production costs in the current quarter were $246 million or $16.91 per Boe, lower than prior-year costs of $271 million, or $18.35 per Boe. This represents an 8% reduction on a per-unit basis. As was the case in the second quarter, the decreases came across the board. Particularly in well servicing efficiency and energy use. Production costs were also aided by lower natural gas prices compared to prior-year levels. Third quarter production costs on a sequential basis were slightly higher as we previously guided. This was mainly due to the seasonal effect of summer power rates in California. However, our third quarter production costs were better than expected, largely due to our continuing efforts to reduce costs and improve efficiencies.

In light of the prevailing low commodity price environment and as Todd noted, we took additional steps in the quarter to better align our work force with the longer term, more moderate price environment. Our third quarter workforce reduction primarily through voluntarily retirements, resulted in a total pre-tax charge of $62 million in the quarter, which is excluded from our adjusted G&A calculation. Accordingly, our adjusted G&A expense in the third quarter was lower both sequentially, as well as on a prior-year basis. The expense rate was $67 million for the third quarter, compared to $75 million in the second quarter of the year, and $78 million in the third quarter of 2014.

A significant portion of these costs will be paid to the effective employees over a period of 18 months. Beginning in the fourth quarter, we expect total annual pretax savings of approximately $50 million, of which roughly $15 million will affect production costs, and $25 million will affect G&A. Taxes other than on income largely reflect ad valorem taxes, which were also lower on a sequential and prior-year basis. Given lower commodity prices and the mid-year reassessment of the ad valorem taxes, third quarter taxes registered $42 million, compared to $53 million in the second quarter 2015, and $56 million in the prior-year quarterly period. Taxes other than on income also include greenhouse gas and production taxes, which remained relatively flat between the periods.

Exploration expense declined on a sequential and year-over-year basis. Third quarter 2015 exploration expense was $5 million, compared with $7 million in the prior quarter, and $25 million in the third quarter of 2014. Decline from the prior year was due to our reduced drilling activity. As I mentioned interest expense in the third quarter totaled $82 million, which was consistent with the prior quarter.

As a result of all of these factors in the third quarter 2015, we recorded an adjusted net loss of $86 million, or a loss of $0.22 per diluted share, compared to an adjusted net loss of $51 million, or a loss of $0.13 per diluted share for the second quarter, and adjusted net income of $188 million, or $0.48 per diluted share for the prior-year period. Third quarter adjusted EBITDAX was $212 million, and cash flow from operations registered $180 million, adjusted EBITDAX was lower than the prior quarter's level of $270 million, and the prior year's $662 million due to lower commodity prices, which were partially offset by the positive impact of hedges and our lower overall cost structure. For the first nine months of 2015, adjusted EBITDAX was $680 million, compared to $2.1 billion for the first nine months of 2014.

Our capital investment registered $95 million during the quarter, which was the same as the previous quarter. I want to emphasize again the third quarter capital investment was within our operating cash flow. Our drilling rig count for the third quarter remained unchanged at three rigs, as in the prior quarter, delivered more wells than planned. At the nine month point our investments have totalled $323 million, or 73% of our $440 million capital plan for 2015. Recall this plan was front-end loaded. For the full year we're on track to come in below our capital plan. On the hedging front, we continue to be opportunistic in the face of a challenging strip commodity price. In the second quarter we added an incremental Brent crude oil hedge for the fourth quarter, and initiated a small crude oil hedge for 2016.

Since then we've extended the existing hedge program to protect our 2016 capital plan using costless collars and a swap. For the first half of 2016, we've hedged 30,500 barrels per day at a weighted average floor of $52.38 per barrel, and 35,500 barrels per day at a weighted average ceiling of $66.15 per barrel. Additionally, we entered into collars for 3,000 barrels per day in the second half of 2016, at a weighted average floor of $50, and a ceiling of $74.42 per barrel. We also entered into a swap for 1,000 barrels per day at $61.25 for the period.

Our debt decreased modestly from the second quarter as our operating cash flow exceeded expenditures. As Todd said, we continue to focus significant attention on deleveraging efforts, giving thoughtful consideration to select opportunities that will maximize value to our shareholders. Many of you realize that due to the springing lien feature in our credit facility, our facility is transitioning to a $3 billion secured borrowing base facility, consisting of the $1 billion term loan, and the $2 billion revolver. We are in the process of providing mortgages to secure the facility, we'll then have an annual review process for our borrowing base, with our first annual borrowing base redetermination in Mary. As part of this process, we held conversations with members of our 20 bank credit facility to discuss an amendment to the facility. The amendment was subsequently approved by our banking group on a unanimous basis and became effective on November 2nd. We appreciate their ongoing support.

The amended financial covenants during the borrowing base period will include a first lien covenant of 2.25 times, and a fixed charge covenant of 2 times. We've maintained a pathway to investment grade at which time the covenants revert to prior levels, with total debt to EBITDAX covenant of 4.5 times, and an interest expense covenant of 2.5 times. The credit amendment provides increased liquidity and flexibility for CRC to manage through the price downturn, and preserves the ability to right-size our capital structure. The facility contemplates the sale or monetization of midstream assets, with no adjustment to the borrowing base. Our team continues to take the proactive steps necessary to reduce our cash costs and enhance our margins. We believe our active cost management and deleveraging actions will position CRC favorably for our 2016 opportunities.

Please note we provided key fourth quarter 2015 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 on other aspects of the results during our Q&A portion of the call. I'll now turn it back over to Todd.

Thank you Mark. In the third quarter, as in the first half of the year, our organization executed exceedingly well on the objectives that were within our control. Our team has continued to drive efficiencies throughout the organization, reducing costs in a manner that has sustained both our high standard for safety and environmental protection, and our production. As a result of our cost reductions and efficiency improvements, we believe that CRC is well-positioned to weather this downturn, and pursue the vast opportunities that our asset base provides once commodity prices normalize. We really appreciate everyone who was able to attend our recent Analyst Day and site tours. The response was overwhelming, and we think the time we spent together was invaluable in educating the investment community, about what CRC truly has to offer. This concludes our prepared remarks, and we now will welcome your questions.

(Operator Instructions). And our first question will come from Doug Leggate of Bank of America Merrill Lynch.

Thanks. Good afternoon everybody. Todd, the CapEx is clearly trending a bit below your $440 million that you targeted for this year. So I guess looking into 2016, you talked about $500 million to hold production flat. Where is the risk to that number now, I know it is a little early for the guidance. But just in the context of the trend that we're seeing. Where do you see that $500 million moving to?

Well, as you said, we haven't provided any guidance. But if the current trend continues, clearly there is a downward bias. But at this time we still want to stick by our $500 million.

And the $67 million beyond that, would there be downward bias for that as well?

I think if this current price environment sticks, clearly you have got to think there's going to be a bias downward.

Great stuff. My follow-up, if I may, your comment I guess in the text of the release, and also your prepared remarks, that this seems like things are taking a little bit longer on the assets sales. But you did if I heard you correctly, you have exchanged term sheets. So I'm just wondering if you could, that sounds pretty much like you have agreements in place. Can you give us some line of sight as to how things play out from here, and whether or not you're targeting. In terms of the order of how you would prioritize things. You're targeting midstream first, and then maybe any update on the explorations and ventures at the same time. Just looking for sort of a game plan as to when we should see line of sight for getting to that first hurdle if you like?

I don't think there's any magic to which one comes before the other one, talking midstream or upstream. I do think we're pretty confident we'll get one signed up, announced by year-end. I think if you looked at the order of events Mark talked about, and we talked about our credit amendment, clearly when you have a springing lien occur in all of this, you need to make sure you put a credit amendment in place that allows you to continue to pursue these activities. So I would argue that there was a little bit of a slowdown in the whole process just for that factor, because the priority of getting that done was more important and critical to the overall process. As Mark said, we just recently accomplished that. So I don't think we're any different than what we talked about on Analyst Day. But again, we probably had a minor downward shift there, as we had to get the credit agreement amendment squared away.

The next question is from Welles Fitzpatrick from Johnson Rice.

Hi, good afternoon.

Hi there.

Can you give us any kind of guide on the California ad valorem tax reassessment, as far as timing? And do you have any sort of indication as to what that might flow through to you all on either a per unit or a total basis in 2016?

This is Todd. It's a lagging change. But I'll let Mark address what we've seen so far this year in the back half of the year.

Welles, Mark here. The ad valorem taxes like Todd said is mid-year. And if you look at, I'm just trying to grab my numbers here. If you look here, you saw that we went down from $56 million to $42 million year-over-year. We think it amounts to about another $0.40 a year on a Boe basis.

Okay. That's perfect. And just one follow-up. The well that you refer to in the prepared comments, is that the deep sandstone test and if so, do you guys have any plans to test, I think you said it was ten offsets that you were looking at?

Yes, that is what we're talking about. And we do have plans in place that we're progressing to look to test the offset locations, and also uphole and downhole and offset wells that currently exist.

That's perfect. Thank you so much.

And the next question comes from James Spicer of Wells Fargo.

Yes. Hi everybody. I'm looking at page 10 of the presentation, the pie chart, total capital budget breakdown by activity. And I'm wondering what this looks like with a $500 million budget, potentially next year or a $600 million to $700 million on an ongoing basis, particularly the infrastructure component, and trying to understand how much of that is fixed versus variable?

So I think as we've said, the fixed versus variable in our operations, we think the fixed is about a third. And the variable is about two-thirds. If you looked at historically and you thought about the facility spending, it was about 30%. I'll say there was some heavy facility spending over the last five to ten years. So going forward I would anticipate that number would be closer to 20% or even less percent overall. And then obviously there's not going to be a ton of exploration happening, because that's something that we can save for ourselves for later. So hopefully that gives you a flavor.

Yes. That is helpful. And for my follow-up, wondering if you can provide color on your current production level. How much of your production is coming from your core steam flood and water flood projects, that are the focus of your capital spending right now, versus unconventional or exploration plays?

I think our expiration as we said historically was right around 20,000 or slightly less than that of Boe a day. Water floods and I think steam floods are around, is about, water floods and steam floods are about half the production overall.

And the next question will come from Brian Singer of Goldman Sachs.

Thank you. Good afternoon.

Hi, Brian.

Wanted to see if you could just provide a little bit more color on the credit agreement, specifically the leverage, the covenants, and how the debt to EBITDA compares with where you are now, and any adjustments that we shall be making when thinking about where you are within that, and then what the ramifications are, if there is any breach?

I think what's important to recognize, Brian, is that with the security, what we did is we moved from a total debt to EBITDAX ratio, back to a first lien leverage ratio, just on the senior bank facility. And that goes to 2.25 times. And then the interest expense ratio was amended down to 2 times, as opposed to previously 2.5 times. So those are the changes in the financial covenants.

Got it. That's versus the total company EBITDA versus the specific of the facility? As opposed to the total debt for the Company overall?

Yes, right. The way to look at it is total bank debt to EBITDAX, as opposed to total debt of the Company to EBITDAX.

Sure. And then just going back to more on the operations side. Can you just talk about production mix over the next few quarters, and we didn't really, as you expected, we didn't see that much of a decline on the oil side. How you expect that as overall total production start to come off?

Yes. If you think about the production and the different drive mechanisms, clearly we're investing most of our capital in steam floods and water floods. So that's creating an oilier mix. I think if you looked at how our gas is trending from a decline rate, I think you could argue that will continue, and I think you could look at the oil, and think that's going to continue very similarly, given the investments we've been making, and I think the trend towards becoming slightly more oilier as an enterprise will continue, as we continue these types of investments.

And the next question is from Sean Sneeden of Oppenheimer.

Hi. Thank you for taking the questions. Maybe as follow-up to the question on the revolver, but when you guys look forward next year, I guess how comfortable are you with maintaining compliance with the 2.25 times covenant? In your minds, does that kind of necessitate when you run your models, necessitate you guys having to do an asset sale to maintain compliance? How are you guys thinking about that in general terms?

As Todd indicated in his remarks, we felt like getting the amendment was a key part of our overall deleveraging strategy. A couple of things. It relaxes some the covenant. It looks at the senior bank to EBITDAX. It gives us more runway there. But it specifically contemplates the sale or monetization of midstream assets or non-borrowing base assets. So there's no reduction to the borrowing base going forward for that sale or monetization. So it allows us to continue moving forward on those transactions. We believe that the amendments that we negotiated with the banks, and that were unanimously approved, gives us a nice runway through 2016 to continue executing on our business plan as we've been doing through 2015.

Okay. And so if I'm understanding you correctly, regardless of an asset sale or not, you feel that you have runway through 2016 currently, right?

I certainly feel that way. Yes.

Okay. That's helpful. And then maybe I guess just lastly, I think it was Slide 11 talked deleveraging the balance sheet. I guess, Todd or Mark, could you maybe walk us through the decision tree, in terms what would cause you to do one of those three options that you've kind of highlighted? I guess specifically what I'm thinking about, what would kind of make you guys go after option number three, the capital markets. Obviously the amendment gives you a significant amount of second lien capacity. When would that really become an attractive option in your mind?

We've indicated that we're actively considering all options to improve our balance sheet. That's what you see on Slide 11. We have not ruled out any alternative that would help us to meet those objectives going forward.

I mean if you think about it, what are we trying to do, we're trying to do the thing that's best for our shareholders. We have pursued any and all options that are potentially available to us. We're trying to do that in a way that's most tax efficient, provides the highest level of operational control, and gives us the most proceeds. We're going to pursue, again what makes the most sense for our shareholders. As it accomplishes all of those objectives.

The next question is from Pavel Molchanov of Raymond James.

Hey guys. Thanks for taking the question. The timetable for closing, if you announce, as you said, one or more transactions by year-end, when would the cash get in the bank, so to speak?

That's a little speculative. But from many, many years of doing transactions, if it we're really opportunistic it could be by year-end. If we're a little pessimistic and the lawyers do their thing, and fill all of the available time, it could go into the first quarter.

Okay. Understand. And then just kind of a small housekeeping item. Last two quarters LOE per unit actually ticked up. Any specific reason for that?

Mostly it's California power prices.

Yes.

Summer rates.

Yes. That's right.

I'm sorry about that. The next question is from Gregg Brody from Bank of America Merrill Lynch.

Good afternoon, guys.

Hi, Gregg.

I flipped back to page 22 in the presentation. And I see some of the amendments that you have in there for potential second liens and debt repayments with asset sales. Can you walk through those a little bit and sort of, I'm trying to figure out where is the $2.25 billion of second lien, and then there is an excess cash sweep concept of $250 million, how that works, and then the baskets for carve outs for paying down debt? Looks like you have to pay down half junior debt, half term loan. Walk us through that a little bit?

I think the underlying premise, whenever you look at the amendment, Gregg, is that there's certain baskets that were out there within the Company's senior notes, and so those baskets were largely preserved as we went through the amendment process with the banks. And so that's why you're seeing that $2.25 million basket, relative to the permitted second liens. And you talked about repurchasing of the junior debt. The banks allow $150 million initial basket, and then 50% of the proceeds to repurchase debt.

What is the excess cash sweep concept of 250? I don't understand how that works?

They just want to make sure that proceeds from any asset sales go first to repay the term loan. And make sure that the Company doesn't leave any excess cash sitting on its balance sheet.

So if you have raised $2.25 billion of second lien, you have to pay down $250 million? You have to pay down the first lien with that?

I think the better way to look at it, is if we monetize a significant amount of our assets, or a midstream asset in a significant amount, we have to repay the term loan, and then we can't leave more than $250 million sitting on the balance sheet.

And then just one more for you. On the asset sales, so I appreciate things might be pushed out a little bit this is sort of the language you used previously was one to two by year end or first quarter, and now you're talking about one. Is anything materially changed or is that just sort of what you're willing to promise by that time period?

Gregg, it's Todd. Yes, in our mind nothing has materially changed. Like I said, we just feel with the credit amendment, there was a little down shift there for a little bit. While we worked to get that done to ensure that we can continue on these other paths, with these other opportunities. And we feel comfortable saying that we'll get at least one signed up by year-end.

And next we have a question from Paul Sankey of Wolfe Research.

Hi, guys. I was just wondering if somehow to keep it simple for me, you could estimate what your oil price breakeven is, in terms of not having any trouble with debts, and just sort of balancing the books, and how that's changing over time? Also your realizations basically exceeded our expectations this quarter. I was wondering if you could sort of relate that breakeven concept to your price versus WTI or Brent? Thanks.

On the breakeven, you're saying -- [apologies], I didn't understand, you were trying to say without any interest coverage or what were you trying to refer to?

No. I think covering anything that you need to keep going, there's an oil price level. I mean, I'm assuming at $50 it doesn't work for you without perhaps the monetizations. So ex-monetizations what's your oil price breakeven just to keep flat and stand still in terms of your debt requirements and interest payments and everything else? Thanks.

Yes. I think what you want to do, if you walk through where we sit on an operating cost, we're $16 and change. You add production taxes to that, then you add G&A, when you add that all together in the new world, you're probably $24, $25, and then you take out a differential and everything else, I think you're in the low-$30s on a cash basis. And then you're going to layer in interest. And so I think you're talking about mid-$30s on a cash basis.

Right. And then once you add in the interest payments and everything else?

Yes. I think that's when you add it all together.

Yes, Paul. Just from a high level our cash costs are running just over $30 a barrel currently. And then if you add interest expenses of just over $300 million, just over $6 a barrel. So that gets you to the mid-$30s that Todd was talking about.

Then if you wanted to assume an F&D on top of that, obviously we looked at some of our projects, you can layer that in, too. But we're talking about here on a cash basis, breakeven like you're referring to.

Yes, okay. I apologize for not attending your offsite, by the way, I did intend to attend, but was sidetracked. Just keeping it so simple, if I was to layer in the F&D, and what I was also getting at is how that is going to change over time, given what you've been saying about your projects, what number should we use for that?

If you look at it and what we've been saying, talking about our typical water floods and steam floods, those are high single digit, approximately low double digit F&D. So if you want to be conservative or aggressive in that range, you're talking about mid-$40s kind of all-in, including an F&D cost.

Next we have a question from Ravi Kamath from Seaport Global.

Hey, guys. One question on the credit facility. Is that something that you'll be filing in an 8-K?

The Credit facility will be attached as a material agreement when we file the 10-Q.

Okay. Perfect.

It is being filed. The 10-Q is being filed today.

Okay. Perfect. And then one follow-up. You said the new agreement contemplates the monetization of midstream assets. Is there a cap to that, is it $2 billion? Is there some sort of cap to how much midstream you can sell?

No. There's no cap on that.

And the next question comes from Jeff Davies of TPH.

Thanks guys. So just back to the production costs for a minute, you guided the fourth quarter to a mid-point of 17. So just again kind of curious on a sequential basis, ticking up again, while I expect power prices coming down and in the context of the recent layoffs?

Yes. You have to remember our production is coming down a little bit. And the other part is we do have some capturing, make sure we capture all of the layoffs and early retirements, and the like.

Well, that wouldn't be baked into the production costs though, right?

Yes. It actually is. When you think about what happened is we had a G&A reduction, and you have got to remember people who are tied to wellbores are actually an operating cost, even though you might consider them overhead. So part of what happened in the downsizing, was personnel that were technically reported as operating costs, and there's also folks who are technically reported as capital, because they're in the drilling function. So you'll have a breakout of approximately half of it is related strictly to G&A. Also you got to remember the summer prices come off about May quarter. We're still going to get about a full quarter, half a quarter of summer power pricing for California.

Got it. Okay. And on the hedges just curious the first half 2016 hedges, did you sell more calls than puts you bought to push up the put price effectively?

It was complicated, because if you remember we had a swap for the entire year. So it was a combination of trading that in and executing new transactions. As you can see, there's slightly more calls than there is puts. And that's where it ended up. But that's effectively what happened.

Okay. Thank you.

And the next question comes from Tarek Hamid of JPMorgan.

Good afternoon, guys.

Hi.

Most of my questions have been asked. But on the capital budget for 2016, sort of roughly talking about $500 million, should that hold production at 4Q-ish 2015 levels in your view, or is it sort of too hard to call, given the fact that production has been frankly better than you thought this year, in terms of the decline rates?

We haven't really given guidance. We've just said $500 million is what we think keeps oil production flat next year. So that's what we're willing to commit to at this time. We'll give a lot more guidance here in February.

Got it. And then on the second lien fronts, I know Gregg asked a few questions on that earlier. But as you think through your options, is the goal in terms of any kind of future liens issuance to be to ultimately reduce the ultimate quantum of debt, not necessarily raise money for the sake of putting more liquidity on the balance sheet?

No. Our stated goal is, as Mark and I have said many times, long-term we'd like to get to 2.5, 2 times. Obviously it seems like a bridge pretty far at this point, but in the medium term, our goal is to get rid of, or otherwise defease in some fashion $1.6 billion of debt by 2016. As we have said before, we're willing to do anything and everything on the cost of our assets across the balance sheet.

And our last question today will come from Maryana Kushnir of Nomura.

Hi. I just wanted to clarify. I couldn't quite reconcile EBITDA versus cash flow from operations. Was there a significant positive effect from working capital, or any other items that contributed to this strong cash flow generation?

We've got a reconciliation, kind of coming at it from both directions in our earnings release.

In our Appendix.

In our earnings release. If you look at page 8, you will see it coming from both directions.

Yes. There was about $50 million of other items, and I guess what are those items?

When you refer to $50 million, are you referring to the income tax expense or benefit?

An adjustment that's listed as other?

Other.

There's 26 for the quarter. 26?

I guess I am looking at the reconciliation, EBITDA versus net cash flow provided by operations?

Yes. So is it 46? Is that what you're referring to, the other net? Is that what you are looking at?

Right. So what are those items?

They're just non-cash charges to adjust to give back to, it's like you accrue for equity comp, and things like that, through the quarter, that are noncash charges.

Okay. Thanks.

And we actually do have another question that comes from Biju Perincheril of Susquehanna.

Hi. At the Analyst Day you talked about some work on steam injection rate optimization. And I was just wondering, is that something you're implementing now, and how should we think about impact on LOE going forward from that?

I mean, if you listened into our Analyst Day, you heard Jeff and Vic talk about this, I think it is something we are working diligently and continues to get better for us, as we look to maintain and optimize the steam levels and the heat rates in the reservoir. So I think over time you're going to see that get better, and ultimately bring our costs down. We're also very tied to the price of natural gas. So if natural gas prices go up, that could obviously override any of our benefits from better steam utilization in the reservoir.

Okay. Thanks.

And this will conclude our question-and-answer session. I would like to turn the call back over to Todd Stevens for any closing remarks.

Thanks everyone. Look forward to seeing you or talking to you soon.

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