California Resources Corp (CRC) 2014 Q4 法說會逐字稿

Hello, and welcome to the California Resources Corporation fourth-quarter earnings 2014 conference call.

(Operator Instructions)

Please note, this event is being recorded.

I would now like to turn the conference over to Scott Espenshade, Vice President, Investor Relations. Please go ahead.

Thank you. I'm Scott Espenshade, Vice President of Investor Relations, and welcome to California Resources Corporation fourth-quarter and full-year 2014 conference call.

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

As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject risks and uncertainties that may actual -- 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 on the Company's form 10. We would ask that you review it and cautionary statements in our earnings release. Our fourth-quarter 2014 earnings press release and some additional disclosures have been posted on CRC's Investor Relations page, which can be found at www.CRC.com.

We have allotted ample time for Q&A at the end of the call today and would ask that participants limit their questions to a primary question and a follow up.

I will now turn the call over to Todd.

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

We're excited by the long-term prospects ahead of us at CRC as a newly public company, but we, like you, are focussed today most intently on the current operating environment, so I'd like to address that first. Notwithstanding record fourth-quarter production and growth in our reserves for 2014, our fourth-quarter financial results reflect a softening of prices which accelerated in the quarter.

Mark Smith, our CFO, will discuss our financial results in detail shortly, after I summarize CRC's 2015 plan to effectively manage our business in the current price environment. I will then cover why we expect our core strength to serve us well in this point of the cycle and then review 2014.

CRC operates a world-class asset base, with substantial operational and financial flexibility, overseen by management and operating teams with deep experiences in all phases of the commodity cycle. These strengths differentiate us and are central to our continued success during a period of lower prices.

To emphasize this last point, CRC, or our California business, has worked its way through many complete commodity price cycles over decades. This includes the price decline seen in the 1980s oil markets. We have a group of managers and employees who have been there and done that. The leverage we are dealing with is different, but the operational responsiveness and the assets have already been tested a number of times over.

We have said that we plan to live within our means and adjust our capital investments to our projected operational cash flow. Our disciplined capital allocation strategy will harness our competitive strengths to sustain economic production throughout the cycle and enhance our net asset value.

Our operational flexibility has been on display in recent months as we quickly took steps to adapt to this new environment. We started an aggressive cost containment program in the fourth quarter.

First, we rapidly reduced our drilling rig count from 27 near the end of November to 6 at year end. In 2015, we expect to have approximately three drilling rigs, active which will primarily focus on development activities in our steamflood and waterflood properties.

Second, we also reduced our workover rig count from 47 in the early part of 2014 to 33 equivalent rigs currently. This level provides our maintenance rig fleet with sufficient capacity to preserve our base production and ensure low production decline rates in this lower-capital environment.

As a result of these reductions, we expect to sharply reduce our capital investments, generally keeping them in line with today's pricing levels and our expected levels of cash flow, while minimizing the effect on our base production. Based on our preliminary discussions with our Board, and subject to their final approval next week, we plan our capital program in 2015 to be in the range of $400 million to $450 million, which represent an approximate 75% reduction from our 2014 capital investment of $2.1 billion.

Third, we have also implemented measures to bring our costs in line with the fundamentals that market conditions dictate. We are working with suppliers in this regard and adjusting our internal processes at all levels to simplify our operating and overhead cost structure. We have already reduced our operating costs in the fourth quarter of 2014 and expect to make further improvements in 2015, along with our general administrative costs.

Our capital budget is based on $60 per barrel brent oil price. If this price should change materially, or if we are unable to realize additional cost savings, we will adjust our budget accordingly.

High on our priority list is balancing any additional investment with the potential for debt repayment. As we assessed our investment plans for 2015, we utilized our value creation index, or VCI, and evaluated each project's ability to generate a net present value greater than 1.3 times the costs over the life of the project.

Again, VCI is calculated by dividing the present value of a project's pretax cash flows over its life by the present value of the investment. You will see that for 2015 we have placed an emphasis on steam- and waterflood projects that offer a lower decline and lower risk profile, while providing attractive returns over their economic lives. While weak commodity prices have affected both oil and natural gas prices, the lower natural gas prices have had a positive impact on steamfloods, which use gas to generate steam, and these projects continue to be very attractive.

Overall, we are not project constrained, even in the current environment. We have many more projects that would still provide attractive returns that we will develop as capital becomes available. We could double our active rig count within a month if market conditions warrant.

This further demonstrates the quality of our asset base and our ability to manage the business and generate cash flow in a variety of different market conditions. For example, well workover activity can often be among the most attractive investments in addition to steamfloods and waterfloods. Also, we continue to focus on building our project inventory for projects to be ready when the cycle turns.

As we look, ahead, we expect our first-quarter 2015 crude oil production to increase modestly from the fourth-quarter 2014 levels, while total production will remain comparable to the fourth-quarter 2014 rate. Expected range is between 160,000 and 165,000 BOE per day. This illustrates that we can continue to benefit from our past investments.

For example, many of our steam- and waterflood projects will continue to deliver production increases for some time after the initial capital outlay. As I said previously, current lower natural gas prices will continue to have a positive effect on our steamflood projects.

If our capital program stays at the level I mentioned through the entire year, we would expect to see a flattening of the oil production as the year progresses. Overall, we expect our average crude oil production to be higher in 2015 compared to the 2014 average, and natural gas and NGL production are expected to be lower. We expect our total average daily 2015 production to be relatively flat compared to 2014.

This month there have been several discrete refinery events in California, which are still ongoing, that could potentially impact our crude sales. While we believe we will be able to sell this affected production, our realizations may be slightly lower that what we'd normally achieve.

I'd now like to address our debt position. As part of the spin-off to finance a one-time payment to our former parent company, we took on $5 billion in long-term publicly traded debt. The maturity on this debt will not be due until 2019 in the earliest tranche and followed by tranches in 2021 and 2024.

In addition, our bank facility includes a $1 billion term loan, which matures in 2019, with principal payments beginning in 2016. Mark will discuss the bank facility and our efforts to amend certain of its terms in detail.

In our the first conference call held back in October and at subsequent meetings held with the investment community, we laid out CRC's key strengths. One, our world-class resource base that contains a diverse portfolio of significant, high return, high potential, conventional and unconventional development opportunities, including IOR, EOR, tight sands and shale that provide a stable, resilient production profile and the flexibility to adjust to different market conditions. Two, a commitment to shareholder value. A disciplined approach to manage and live within our cash flow and maximize our returns within our investments using our VCI metric to build shareholder value with each investment.

Three, strong leadership and operating teams with extensive experience operating in California and proven management and technical expertise to develop our prolific resource base and manage not through commodity price cycles, but through cycle troughs specifically with these assets. Four, a California heritage of proactive engagement with regulators, communities and other stakeholders that creates mutually beneficial outcome.

As we enter 2015 we believe each of these key strengths will place us in position to manage our business in a lower-price environment.

Now turning to our 2014 highlights. The fourth quarter was notable for CRC as we completed the spinoff from Occidental Petroleum on November 30, 2014, and became an independent publicly traded company on the New York Stock Exchange the following day. I applaud our work force for the safe and effective manner in which they completed the spinoff.

Since that time, the steep decline in oil prices that started in midsummer continued and dampened our fourth-quarter financial results. We achieved record quarterly oil production of 105,000 barrels per day on average, 5% higher than the third quarter of 2014 and 12% higher than the fourth quarter of the prior year.

Most of the increase came from our conventional steam and waterflood projects, predominately in the San Joaquin Basin. Our total average production for the quarter of 165,000 BOE per day was also a record.

We added 118 million barrels of proved reserves from our capital program in 2014 for a 103% organic proved reserve replacement ratio. We continued to achieve significant capital efficiencies in 2014, reducing the costs of joint projects by approximately 10% compared to 2013 on top of the 20% achieved that year. This resulted in total 2014 capital investments of $2.1 billion and a significant reductions in the cost of adding proved reserves, from $19.16 per BOE in 2013 to $17.68 in 2014.

We ended 2014 with 768 million barrels of oil equivalent of proved reserves, which had a PV-10 of about $16.1 billion, compared to 744 million barrels of proved reserves and a corresponding PV-10 of $14 billion at the end of 2013. Our year-end 2014 proved reserves consisted of 72% oil, 11% NGLs and 17% natural gas, which was consistent with 2013. Our proved developed reserves at the end of 2014 representing 72% of our total proved reserves, an increase from 69% in 2013.

Let's now review some of our operational highlights in 2014. We continued our successful near field and impact exploration programs in conventional and unconventional reservoirs. Our exploration program delivered a geologic success rate of 80% with approximately half of these successful wells determined to be commercial in the current price environment.

Notable successes include our conventional reservoir drilling results and proven play trends, offsetting the Pleito Ranch Field in the San Joaquin Basin and Barksdale Field in the Ventura Basin. In the San Emidio trend, two exploration wells successfully extended the Pleito Ranch Field. Both wells encountered the primary producing reservoir of the Pleito Ranch Field at similar reservoir depths and pressures. Additional step-out exploration prospects have been identified and can further extend this trend.

In the Ventura Basin, one expiration well encountered two hydro-carbon bearing reservoir intervals and successfully extended the depth of the known producing reservoirs. We have multiple analogous prospects in this play trend that extends for approximately 30 miles on shore in the Southern Ventura Basin.

We continue to develop our understanding and knowledge of the significant prospective resources in the exploration of shale reservoirs. In 2014, we completed significant log, core and seismic data acquisition projects targeting the Kreyenhagen expiration shale reservoir, around the Kettleman North Dome and Middle Dome Fields.

We completed seven workovers and existing well bores and drilled six new wells. In many cases, zonal completions were implemented to assess the expected performance of individual zones of interest and identifying landing zones for potential future horizontal development.

Meanwhile in the development side, CRC drilled 1,048 wells overall, of which 73 were focused on primary production, 259 were in waterflood fields and 532 were in our steamfloods and 184 wells were drilled in unconventional reservoirs. In the San Joaquin Basin, we drilled 847 wells, consisting of 725 producers and 125 injector wells.

We invested approximately $900 million in drilling capital in the San Joaquin Basin, an additional $900 million for the acquisition of producing and mineral interest and $105 million on exploration. Out 2014 production in this basin averaged 64,000 barrels per day of oil, 180 million cubic feet per day of natural gas and 18,000 barrels a day of NGLs.

In our Los Angeles basin assets, which are mostly waterfloods, we drilled 177 wells with 123 producers and 54 injectors. The capital invested for this drilling activity was $340 million. We produced an average of 29,000 barrels per day of oil and 1 million cubic feet per day of natural gas in this basin.

In the Ventura Basin, we drilled a total of 21 wells, of which 19 were producers and we also had two steam-injector wells. The capital invested on these wells was $43 million.

We also made an acquisition of properties in the fourth quarter for $200 million for the West Montalvo Field. We produced 6,000 barrels per day of oil, 11 million cubic feet per day of natural gas and 1,000 barrels per day of NGLs in this basin.

Lastly, we drilled three natural gas wells in the Sacramento Basin in early 2014 for a cost of $7 million. CRC produced an average of 54 million feet a day of gas in the basin in 2014.

As we look into the future, if the current conditions persist, we expect our production levels to be affected, since we will not look to accelerate production into this price environment. In the past three years, we increased our oil production at an average 8% annual compounded rate.

Additionally, the share of our steamflood projects has gone from 16% to 19% over this period. We currently continued to focus almost entirely on oil drilling, which still provides higher margins and cash flows compared to other parts of our portfolio.

Further, in the short term, as I discussed earlier, much of our capital will be directed toward conventional steam and waterflood projects, which have lower risk and much lower declines than unconventional projects. As a result, we expect that the overall decline rate of our total production will start flattening, which will reduce base maintenance capital levels. Over time, this effect should moderate the downward pressure that a reduced capital program will put on our production levels.

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

Thanks, Todd.

As Todd noted, the fourth-quarter results reflected a steep decline in prices combined with charges related to the impairment, the spinoff and our transition to an independent company. Our overall production, particularly our oil production, reached record levels. We simultaneously took swift action to address the changing the environment.

We're reducing our capital investment profile, reducing spending, shrinking our active rig count, defending our margins and generally making the adjustments needed to live within our reduced cash flows, all while protecting our base production. We expect to be prepared to capitalize on renewed opportunities when the market environment ultimately improves. In the following comments I'll describe in greater detail those steps.

I'll first examine our production results; second, the impact of the pricing environment; third, our predictable production profile and cash flows; fourth, our balance sheet and capital program, including our senior bank facility and our hedging program; fifth, the non-cash impairment charge; and finally, our 2015 capital program.

First, our core results from the first quarter of 2014. These exclude charges related primarily to the non-cash impairment charge, spin and transitional-related expenses as well as rig idling charges.

Core results were a loss of $7 million, or $0.02 per diluted share. Now this compares with core income of $212 million, or $0.55 per diluted share, for the fourth quarter of 2013 and core income of $188 million, or $0.48 per share, for the third quarter of 2014.

Now let me turn to our production. Consistent with our strategic focus on oil-related projects, we registered a double-digit year-over-year increase in our oil production during the fourth quarter.

Oil production averaged a raged a record 105,000 barrels per day and increased by 11,000 barrels per day, or 12% year over year. It rose 5,000 barrels per day, or 5% sequentially, from the third quarter of 2014. Our steamflood operations in the San Joaquin Basin accounted 5,000 barrels per day of this year-over-year improvement and it reflects our increased investments in steamfloods.

Our other San Joaquin Basin assets, together with our Los Angeles and Ventura Basin assets, contributed another 6,000 barrels per day of the increase. The natural gas and NGL production both declined from year-ago levels as we continue to focus our drilling programs on oil and reduce our natural gas activity.

Total oil and natural gas production average a record 165,000 barrels of oil equivalent per day for the fourth quarter, an increase of 8,000 BOE per day, or 5% year over year. This was up 5,000 BOE per day, or 3% sequentially, from the third quarter of 2014.

Now, offsetting the positive effect of increased productions was a continued steep decline in oil prices during the fourth quarter that Todd discussed. Realized crude oil prices averaged $68.54 per barrel in the fourth quarter of 2014. This compares to $99.32 per barrel in the fourth quarter of 2013, a decline of 31%.

I want to point out that the Brent index decreased approximately the same percentage over this same period. We sell all of our crude in California markets and we've discussed that these typically reflect international water borne prices.

Our realized NGL prices also decreased in the fourth quarter 2014 to $34.41 per barrel compared with $57.73 per barrel for the fourth quarter of 2013. Realized natural gas prices increased 9% to $4 per MCF from $3.68 per MCF in the fourth quarter of 2013.

In the third quarter of 2014, realized oil, NGL and gas prices averaged $96.27, $47.20 and $4.24, respectively. The results of the production and price changes saw us generate $480 million of cash flow from operations and $454 million of EBITDAX in the quarter.

For the year, our operating cash flows and EBITDAX were $2.4 billion and $2.5 billion, respectively. Capital investment for the quarter was $520 million, with $2.1 billion invested for the full year.

I want to emphasize that we were free cash flow positive for the year. Despite the significant commodity price decline, our fourth-quarter investment rate was close to our operating cash flow level. Now, this was accomplished with the decisive measures we implemented to adjust our capital investment rate to the current price environment.

During the fourth quarter we reduced our capital investment levels each sequential month and our December investment rate was down significantly. This was driven largely by a significant reduction in rig count. To put this in a perspective, we were running 27 rigs in late November, had dropped to 6 rigs by year end, and as we moved into 2015 we continued to bring our rig count down and are now running 3 rigs. This positions us to control our monthly investment rates within our targeted cash flow levels and to achieve our full-year 2015 capital program goals.

Consistent with our proactive CapEx reduction, our cost containment program also had a positive effect on our operating expenses. Production costs for the fourth quarter of 2014 were $243 million, or $16.07 per BOE. This compares to third-quarter 2014 costs of $262 million, or $17.74 per BOE. This represents a sequential quarterly decrease of $19 million, or 9%, and a $1.67 on a unit basis.

Production costs for the fourth quarter of 2014 were unchanged on a dollar basis from the fourth quarter of 2013, but were 5% lower on a unit basis. On a year-over-year basis, the lower fourth-quarter costs reflected lower power costs as well as other cost containment measures and improved well servicing efficiency. To put this cost containment into context, December lease operating expenses decreased roughly 8% compared to our average third-quarter level and this trend has continued in January, declining still further.

Taxes, other than on income, increased from $44 million in the fourth quarter of 2013 to $54 million to the fourth quarter of 2014 due to higher property taxes but were comparable to the prior quarter in 2014. Exploration expense was $33 million higher in the fourth quarter of 2014 compared with the fourth quarter of 2013. Higher dry hole expenses and one time seismic licensing fees associated with the spinoff accounted for the increase. Our overall 2014 effective tax rate was 41%.

Fourth-quarter 2014 interest expense was $72 million, reflecting our capital structure as an independent company. Recall that in October we raised $5 billion through a senior notes offering and distributed the proceeds to Occidental in the fourth quarter as part of the spin. We made an additional distribution to Occidental out of proceeds of the $1 billion term loan and we on borrowed $360 million on the revolving credit facility, largely to finalize certain spin-related items with Occidental and to pay for a fourth-quarter $200 million acquisition of West Montalvo in the Ventura Basin.

Let me now turn to our debt. We ended 2014 with debt on our balance sheet of just under $6.4 billion. We expect our total debt level to increase slightly in the first quarter of 2015 as a result of the working capital contraction that I'll describe shortly. Based on the investment program we've discussed and price levels consistent with the forward curve, we expect to exit 2015 with a debt level generally flat, potentially down compared to year end 2014.

Given the significant overall depth and duration of the decline in oil prices, we're closely monitoring the effect this environment would have on compliance with our existing debt covenants if conditions were to persist. We've received very strong support from our bank group for a 24-month amendment to our revolver and term loan that we believe will provide us with additional cushion to adequately weather the weakness in the current price environment. We expect the process to be concluded in the very near future.

As those of you who follow our sector know, accounting guidance requires us to evaluate the carrying value of our properties on a regular basis, based on movements in commodity prices. As a result of the significant decline in the forward curve at year end 2014, we recorded a non-cash property impairment charge of $2 billion after tax.

This non-cash impairment was related to certain properties in the San Joaquin and Los Angeles Basins and a portion of our assets in the Ventura Basin, as well as our natural gas properties in the Sacramento Basin. We continue to believe that a substantial portion of these assets will become economic as prices recover to more sustainable levels and we would expect to develop them over time.

Other non-core pretax charges during the quarter included $52 million for rig idling and other price related charges, and $55 million for spinoff and transition related items. As a result, we reported a net loss for the fourth quarter of $2.1 billion, or $5.47 per diluted share, compared with net income of $212 million, or $0.55 per diluted share, for the fourth quarter of 2013. There were no non-core charges in 2013 or in the third quarter of 2014.

Turning now to our 2015 capital investment plan, the capital program that Todd discussed is consistent with the operating cash flows that we expect in our business to generate in the current environment at about current prices and with our assumed cost savings.

However, in 2015 we expect to see a working capital contraction of approximately $300 million. This will result from cash payments in the first few months of 2015 associated with our capital investment projects that we completed in the fourth quarter of last year. And we expect to see the situation affect our cash flows in the first quarter of 2015.

For the rest of the year, we expect our cash flows should match, or slightly exceed, our capital program, assuming no further deterioration in oil prices. We expect to achieve this results through our focused capital investment program as well as continued containment initiatives we're undertaking at all levels of the organization.

Given the recent volatile and deteriorating oil price environment as well as our leverage, we began a hedging program shortly after the spin. This is designed to protect our down side price risk and preserve our ability to execute on our capital program.

In December, we purchased put options with a $50 Brent strike price based on a monthly average. This initial program covers almost all of our oil production for the first six months of 2015.

More recently, we put into place addtional hedging instruments to protect the pricing for almost two-thirds of our expected third-quarter 2015 oil production. For this program we chose a combination of Brent-based callers of between $55 and $72 per barrel for 30,000 barrels per day for the period July through September. We also purchased put options at $50 per barrel Brent for 40,000 barrels per day, combined with the sale of the $75 per barrel Brent call for 30,000 barrels per day of oil production in March through June of 2015.

Going forward, as an independent company, we'll continue to be strategic and opportunistic in implementing our hedge program. Our objective is to protect against the cyclical nature of commodity prices and underpin the cash flows necessary to implement our investment program.

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

I'll now turn it back over to Todd, who will discuss our plans for 2015.

Thank you, Mark.

In closing, we had a very successful 2014, growing our reserves, increasing production to record levels this year, as well as planning, executing and completing the spinoff from Occidental into the middle of a cyclical downturn in commodity prices. We believe this has provided an excellent opportunity for our long-term investors that understand our business in California and recognize our key investment highlights.

We have a world-class resource base, which contains a diverse portfolio of significant higher returned, high potential, conventional and unconventional opportunities, a laser focus on shareholder value and the management expertise and heritage to execute our business plan in our under-exploited California assets. More importantly, we have taken positive actions for CRC's first full year of operations as an independent.

We expect 2015 to be an exciting but challenging year, based on the current price environment. But we stand ready. CRC's operational control for a diverse portfolio of steamfloods, waterfloods and primary assets provides us the flexibility to apply a disciplined cash management and cost containment program to maximize the value of our tremendous resource base. We believe CRC is very well positioned to manage our business through this environment and set our organization up for a future profitable growth.

This concludes our remarks and we welcome your questions.

(Operator Instructions)

Doug Leggate, Bank of America.

Thanks. Todd, I wonder if I take two related questions, please, on debt. The first one is, obviously given the October Analyst Day, when you laid out a pretty aggressive growth program, the role that you pointed out has changed dramatically. I'm wondering, how has your strategy or your thinking changed in the event of an oil price recovery. What I'm really thinking here is the priority of investing for growth versus reducing debt, given how significantly leveraged your equity volume would be, to basically be balancing the capital structure and I've got a follow up.

Good question, Doug. Considering we look like the day after the LBO with regards to the capital structure and with the changing commodity price environment, I think we would balance very carefully and look very strongly at deleveraging and taking our balance sheet to a more moderate pace, considering that $100 oil is very far away and we would look to deleverage probably more than look to grow in the short to near term, and even the medium term at this point in time.

Is there a debt target that goes along with that, Todd?

I think we would have to wait and see where product prices, commodity prices stabilize. But we want to have the right capital structure and arguably, when we were spun off by our former parent we had appropriate of capital structure for that environment and it deteriorated rapidly. So we would like for it to stabilize, but clearly our current capital structure is not built for a $50 oil price environment. So we would look to deleverage over the short to medium term. And we think that best increased values to our shareholders also.

Sure. My follow-up, I guess, is related, so I guess this one would be for Mark. Mark, I realize your debt is obviously senior debt but there are some covenants that I guess attach themselves to some of the commercial paper. Can you just talk to where the 4.5 times trailing net debt EBITDA metrics need to go in order to -- if oil prices do stay at $50 I'm guessing (inaudible) breach those covenants. How should we think about credit risk from that point of view, if a total is even worth bringing up or what that (technical difficulty) have you got in place? I'll leave it there. Thank you.

Doug, I think it is a very fair question and I'd like to try to answer it head on. We work to continually monitor our forward-looking performance. As we move through the fourth quarter of last year into the first part of this year, we continued to engage in significant planning work. As we did, we saw potential for tightness in our covenant beginning sometime in the late second quarter, early third quarter. As a result, we approached our lead banks, began discussions around appropriate modifications to allow us to continue executing on our business plan, as Todd's laid out, through this in price environment.

As I indicated, we've received strong support from our bank groups. We have a proposed amendment that is very well advanced in the process. It involves relaxation of financial covenants, for a 24-month period, Doug, and the facility would continue to remain unsecured. We're well advanced in the process and as I said, we expect it to be concluded very shortly.

That is really, really helpful. Thanks very much, guys.

Evan Calio, Morgan Stanley.

Good evening, guys. A few questions on 2015 CapEx guidance. I presume part of your ability to take the 2015 CapEx that low relates to some benefit from 2014 CapEx spending, primarily there in steamfloods where you spent about $1.4 billion on those programs in 2014? Do you have an estimate for maintenance capital to stay flat in 2016 behind a year of lower activity? I'm just trying to get to maybe a more normalized maintenance CapEx number to remain flat.

If you look at -- earlier on, as we were early in talking with the investment community, we talked about maintenance capital in the $1 billion range and here we talk to $450 million. I think as we've looked and done our life and field planning and started focussing on creating value over the life of all of our potential investments, it's changed our thinking on maintenance capital as we get away from the short term focussed capital allocation. So I would say we're closer to the bottom number than the top number. And if you thought about a benefit from last year to this year, we calculate about 1,500 barrels a day equivalent that came into the year of benefit from investments in the fourth quarter. Clearly we're benefiting from the some of the facility spending because now we're drilling on some of the steamfloods, but we also would carry over to the best of our ability somewhere around a similar amount into 2016 next year on some of our similar programs we're doing this year on steamfloods.

Great. What is the base decline in the portfolio? I know you mentioned a low decline rate. I'm trying to square the circle with your 2014 CapEx at $2.4 billion -- $2.1 billion to drive 6% to 9% growth and now you're $450 million to hold flat. I guess what is the decline rate? That will tell you that expensive that growth that was before.

Overall, the decline rate, if you take into account down time for maintenance, well downtown, (inaudible) down, pumps down, it is about 15%. If you looked at it -- for the whole Company, but if you looked at it for just reserves and didn't figure out any down time or anything like that, you are going to get about a 10% decline over all at the Company. You also have to balance that out with, as we continue to make investments in waterfloods and steamfloods, we're going to continue to flatten that decline. The decline for 2016 should be better than the decline for 2015. That is without any down time and with what we think would be a prudent amount of down time in our planning processes.

If I could just one more. Just a follow-up on Doug's question then and how that relates to potentially changing the Company's strategy into a recovery. I know you mentioned that you would shift to some deleveraging. In you stuck with the core assets, is there any thought to deleveraging or paying a dividend and really foregoing some of that growth which on a per barrel basis on the CapEx is pretty expensive, at least based on 2015 to 2014 capital spending?

Like I told Doug, I think that deleveraging in this environment with the balance sheet that we have is a way to accrete value to our shareholders rather easily. Even in our current plan for this year, we built in a very modest amount of deleveraging in ourselves, with a small capital budget. But that would be our priority, particularly if the commodity price cycle, it settles much lower than where it was historically in the last few years.

I just meant into a recovery, right? Into a recovery with -- is there a potential shift in the strategy to maintain with these more efficient assets and delever or dividend verses pursuing a more aggressive, broader asset growth program?

Defiantly. I think that's something -- nothing is off the table, but I mean, that's -- we're managing the business today, but if you think about in the future, if we got into a point where we were in a recovery situation and we felt good about the balance sheet, clearly we would become a dividend payer. We would talk about that with our Board and figure out what is the best way to return -- get a return to our shareholders, whether it's returning capital through dividend or share price increases, we'll do it at that point in time, when we're presented with that opportunity.

Great. Helpful, guys. I'll leave it there.

Paul Sankey, Wolfe Research.

Sorry to follow up on a previous answer that you may have given clearly but I may have missed. I guess a big question here is the extent to which you want to delever before you move to the next phase decision, which would be whether to pursue growth or dividend. Did you give a target for where you want to get your leverage down to before you move on to that next phase? I think I missed it.

Yes, Paul, we haven't really given a target. We want to wait and see where the commodity prices settle at. But clearly our balance sheet is a little much on the debt side for us right now and we will look at any and all alternatives to deleverage here, whether it be quickly or slowly going forward, but we haven't really determined what is the optimal capital structure until we really see a settling in the product prices.

Understood. Sorry, what would be a quick option in terms of delevering?

If you look at different ways -- you can look at all kinds of different things and I'm sure that you could do stuff with a joint venture with people on different assets we have that aren't getting capital in our smaller capital budget. You could look at selling things. You could look at (technical difficulty) things to MLPs. You could just start thinking about all of the different way you could do things, right?

Just to clarify and, again, forgive me if I've slightly misunderstood this, but I think the first half is hedged with puts at $50 is that correct? And then you talked about collars. What were the time frames on the collars? If I understand the collars, I guess they would be costless, so essentially you, I guess, sold a call and bought a put for zero cost? Is there a high cost associated with the $50 puts the you're prepared to reveal if we don't finish below $50? I guess we hear giving away the upside above the top of the collar and the downside below based on the way the collars have been set? If you could repeat of the time frame of the collars, that would be great. Thanks.

I'll talk about the first six months. Yes, we have $50 puts. They were not expensive in the grand scheme of things when we purchased them shortly after our spinoff. And that which for the first six months of the year for substantially all of our oil production, and since that time, in the last few weeks we've executed a costless collar for the third quarter which is between $55 and $72 and that is for 30,000 a day. And then we also have put in put options in place for that same time period at $50 in addition for 40,000 a day. And then we've sold a call at $75 for our production from March to June, so effectively putting in a collar on our heretofore only the put we had for that part of sort of the second half of the year, second quarter.

Understood. And then rolling forward, is that kind of ongoing strategy that you'll expect into 2016 and beyond?

Yes, I think the plan is to be strategic and opportunistic here, and given our balance sheet, it is not prudent to be unhedged. We don't have the balance sheet of our former parent and could ride out commodity price cycles like they could. Maybe one day we'll be in that environment but we're not in that environment now. We will look to be opportunistic and lay in hedges that will ensure (technical difficulty) enough cash flow to function and continue is a going concern.

Thank you very much for your help.

James Spicer, Wells Fargo.

Hi, good afternoon, everybody. I just had a follow-up on the capital allocation for 2015. How much capital, if any, do you expect to spend on the unconventional portfolio? And just what's the decline rate there, and are there any lease expiration issues?

There are no lease expiration issues and the amount being spent on the unconventional side is very tiny and I think it's one particular project. It has an outstanding DCI, even at even lower prices, but all the way down to $40 and, as a matter of fact, Brent. But that is a discrete project that we're talking about and it's a very small part of the overall program.

I was under the impression that unconventional was about a third of your production in 2014 and probably about the same amount in PV10 value.

Yes, that's -- due to a lot of legacy drilling, particularly at Elk Hills and some other properties like North Shafter, there is a lot of unconventional production currently, PDP production, but we're not doing a lot of drilling in the current price environment. Just optimizing that base.

And did -- can you just tell us what the decline rate is on that unconventional production, given that you're not allocating capital to it?

It is hard to say. Just at Elk Hills we have 75 different type curves. For us to give you one particular decline rate, it is not like the unconventional you hear about elsewhere in the country. I think the steepest decline we have on some of our unconventionals might be 30% as opposed to the 60%-plus that you might see somewhere else in the country. But I think we have been able to temper and work our base declines lower than that number I just gave you.

Okay. Understand, thank you.

Sean Sneeden, Oppenheimer.

Thank you for taking the questions. Just maybe one quick follow-up on your leverage question that people have kind of been hitting on. Just considering your comment, Todd, on finding more appropriate capital structure, could you just kind of talk about if the current forward curve plays out as it is right now, how you kind of plan to get there? It kind of sounds like the preference is more on the asset sale, JV, or perhaps more creative financing, versus using more traditional capital markets, if you will?

Yes, I think we're looking at all options. I think the rather than taking baby steps and working ourselves up operationally with a small capital budget, I view we have an enormous resource opportunity here and we're sitting on a lot of potential that historically was at Occidental, who had an enormous capital structure and could wait out the time to develop that in a logical process in the scheme of a huge portfolio. Now we're going to look at different opportunities and I think the shortest version is looking to partner with folks who want to come in and be a part of these projects and opportunities, whether it be exploration or other things we might have. Not saying we're going to be conducting any kind of fire sale or anything, because we'll convert to baby steps and we'll just continue what we are doing because we think we have a good plan to make it through this cycle and continue to delever, but if we can do it in a way that makes sense, that creates more value in a shorter time frame, we'll do that also.

Sure. I think that makes sense. Is there an internal preference for the structure of those type of deals? For instance, is it more of a preference on having cash up front to be able to use that to reduce debt? Or are you kind of open to using a normal carry as well?

I think we're still looking at everything and anything. Clearly, from our standpoint, if we're going to delever we would like to have some cash. But like I said, we haven't made our mind up on anything. We're trying to do what is best for the Company and for our shareholders. We haven't really made any decisions on that front.

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

Pavel Molchanov, Raymond James.

Guys, thanks for taking the question. Kind of along the lines of the one of the earlier questions about acreage being potentially at risk, are there any drilling permits that you're effectively giving up, particularly fracking-related permits, by suspending that program?

No. Basically, the way that the interim SB4 and the SB4 regulations will work, and that's the stimulation regulations here in California, those permits are good for 12 months and we are working that, and there aren't any that are going to expire. We execute those strategies into almost into a manufacturing process as we work it through here in the state.

Okay. And then kind of a housekeeping item, if I may. In the past, you've historically enjoyed getting premium to WTI in your oil pricing, but it was 94% of WTI in Q4 on less than 100% for the year as a whole. Is that something that you expected to continue, kind of those discounts or do you think your pricing will revert back to a premium?

I think you really have to just look at Brent. We have a correlation in R-Squared with Brent of 80%. That varies a little bit as a percent of Brent, depending on discrete events here in California. Because really, in California, because it is a captive market, it's competing against the world water-borne prices essentially, so the reality is if you have a discrete event like what happens in Torrance yesterday, that is going to affect the California market. It is going to back off water-borne crude coming here.

So that's the kind of events that typically affect differentials here in the state. We're heavily tied to Brent more than WTI, so you'll see us really get moved back and forth relative to Brent and in recent history, have been at a premium to TI, but it is really just matching what is happening with Brent more than WTI.

Okay. Got it. And lastly, on your production guidance for the year, I know you're not kind of giving us quarter by quarter at this point, but is it fair to say that aggregate production may exit the year 6%, 7% below current levels?

Yes, I think there is enough out there if you look at what we will put out in our 10-K shortly and what we put out in the first quarter, the 160 to 165, and if you look at it relatively flat to the 159 of last year, you can kind of back into that calculation.

Okay. Fair enough. Thanks, guys.

Gregg Brody, Bank of America.

Hey, guys, just a couple of small, quick questions. Can you talk a little bit about cash taxes for this year? And then also I don't know if you mentioned on the call, just what you're thinking about the dividend.

I'll just -- I'll talk about the dividend real quick. The dividend was put in place. There is a very nominal dividend to attract certain shareholders that, that's important to them. Looking in giving us a baseline that we could build on one day if we change to that business model. So it is de minimus in the grand scheme of things and we continue to talk with the Board about it but we believe that we'll continue to have a dividend.

Gregg, this is Mark. We don't expect to pay any cash taxes in 2015 at current price levels and current budget plan.

No -- you're not expecting a refund?

No.

And just to hit on that, the idea of deleveraging, it sounds like you're thinking about a lot of ideas. Is there a time line for you in terms of when you think you start to make a decision moving forward on all of the different opportunities you were kind of mentioned for deleveraging?

We have been looking at this for some time, clearly as the markets deteriorated. There is no gun to our head, but we are going to do what makes sense. It could happen quickly, it could happen slowly. We're not going to rush to do anything. I feel like with the amendment that Mark talked about that's pending shortly, we'll be in good position to weather the storm going forward and don't need to really have to do anything, but we'll do things that make sense and create value for our shareholders.

Thank you very much.

John Herrlin, Societe Generale.

Two quick ones. Regarding doing an MLP, is it conceivable that you could put in some of the power gen assets like at Elk Hills or are you thinking mainly processing?

I think when you look at that, we've looked at all of the midstream type assets. But there are a lot of complications because we are in partnership down in Long Beach that we don't think those assets would belong in anything like that. And it is something that I think that's further down our list of what would create value because I think it would cost more of an operational issue for us than create real value for our shareholders.

Okay. That is fair. With respect to the impairment that you took, was it mainly SUC BV -- SUC 5-year roll timing and pricing? Any performance issues there? Can you give any more color there?

There was one historical performance issue related to a legacy project from almost a decade ago. Everything else was price-related.

Okay. Thank you.

Phillip Pennell, Mariner Investment Group.

Thanks for taking the call. I'm wondering in terms of what you guys took from Oxy, is there any cash tax impact from cutting CapEx significantly so that you're not drilling, putting more money in the ground, forestalling paying cash taxes in the future?

No, no, none of that.

None of that? So everything that you've written off, you get to count against the future tax bills that you got?

It is a book write-off. It is an accounting impairment. It is not related to tax.

Okay. So it doesn't impact the deferred tax liability that you have at all?

It does impact deferred tax because deferred tax is really comparative between book and cash tax. But the impairment was book-tax driven.

Okay. But bottom line, you're not going to have a cash tax impact from this next year.

No.

Okay. My other question is, with regard to the net capitalized costs after you take the write-down from the ceiling test, or how ever you guys do your accounting, what's the total net capitalized costs?

BP&E post write-down is $11 billion.

$11 billion?

Yes.

Okay. Thanks.

[Aymer Talana], BRT Capital.

Hi, guys, I have a couple of questions. The first one is with respect to the refinery situation. Do you sell directly into that? Secondly, how should we think about this? Is this more of a price impact statewide, or whether it's going to affect volumes?

Again, California is a pretty captive market and it brings in water-borne crude in most cases, small amount of rail crude. It will affect differentials. As far as selling to the Exxon Torrance refinery, historically we have, but currently, before this incident, we were not selling to it. So but it will impact the market, generally, here in the state, and it should cause a little widening of the differentials over the short term until it comes back on board.

Understood. Secondly, I know it is probably a little tough to answer, but when we look at your proved PV -10s, is there a price sensitivity to the price of oil that you can sort of guide to, or perhaps tell us what the current strip would imply in terms of values? Is there some color you can give us there?

We haven't disclosed that and I think again, we're in over 130 fields in California, and so many different ones and they're all discrete in different ways of looking at them. That is why I try to break it out by the different drive mechanisms that you'll see in the 10-K here in the next few weeks.

Understood. Thank you very much.

Anne Cameron, Hartree.

Hi, thanks for taking my question. Your proposed amendment to the credit facility and term loan, I am wondering will that have a cost to that in the way of a different interest rate? Would hedging be a part of that?

We're still in the process of working that and dealing with the banks on that. I've disclosed all that I'm comfortable with disclosing at this point in time.

Okay. Thanks. And in terms of your deleveraging, is there anything that would prevent you from issuing stocks, such as your tax-free spin from Oxy? Are there any prohibitions on issuing new stock?

There is a tax-free nature of the spinoff that would be jeopardized and we've effectively indemnified Occidental for that. So there are some considerations there. I think from the standpoint of issuing shares that is the absolute last thing we want to do is dilute any of our shareholders. We think it would be a much better outcome to find other ways to pay down debt.

Okay. Thanks. Just the last one on your LOE, is it -- can we expect to see that come down in the coming quarters in a lower commodity price environment?

Yes.

Okay. All right. That's it for me. Thanks.

Donald Besser, Manchester Management.

Yes, thank you. I've been noticing so many of the companies reporting their PV using old prices. What is the price you used for the $16.1 billion of PV at the end of 2014?

That price is dedicated by the -- sorry, it is dictated by the SEC and they require you to use the first of the month average for all 12 months in that year. It got away from the prior years where you used just one day of the year. And they -- and the actual price that was used is $95.18 per barrel for oil, $49.93 for NGLs, and $4.72 for MCF and natural gas. That was the one that the SEC dictates you use for 2014.

But then you made this write off, which is determined because of lower prices. That is the accountants applying their own merits to it?

Yes. This is Mark. That's correct. The accounting guidance requires us to use a -- under successful leverage requires us to use a forward look based essentially on the forward curve.

Okay. So that makes us current, that one.

The SEC requires us to report on backward-looking 12-month basis, as Todd described and the accounting guidance makes us look at the carrying value of our assets on essentially the forward curve at the same point in time.

Okay. Thank you very much.

Sure.

This concludes our question-and-answer session. I would like to turn the conference back over to Management for closing remarks.

Thank you, everyone. Please contact Scott or any of us here in Los Angeles with any of your questions. Bye.

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