California Resources Corp (CRC) 2015 Q2 法說會逐字稿

Good afternoon and welcome to the California Resources Corporation second-quarter earnings conference call.

(Operator Instructions)

Please note, this event is being recorded. I would now like to turn conference over to Scott Espenshade. Please go ahead.

Thank you. I'm Scott Espenshade, Vice President of Investor Relations. Welcome to California Resources Corporation second-quarter 2015 conference call. Participating on today's call is Todd Stevens, President and Chief Executive Officer of CRC, and Mark Smith, Senior Executive Vice President and Chief Financial Officer and also several members of the CRC executive team. I would like to highlight that we have provided slides on our Investor Relations section of our website, www.crc.com. These slides provide additional insight into our operations and second-quarter results.

Also in earnings release this afternoon, we noted CRC will be hosting a site tour on Analyst Days in October. The site tour will be held October 12th through the 14th and will consist of a visit to our Wilmington Field in Long Beach and our Elk Hills operations outside of Bakersfield. We believe this will be a great opportunity to see the assets first-hand as well as learn more about our waterfloods and steamflood operations. Please note that we have limited space available due to travel logistics and safety considerations. We also plan to webcast the presentations and will post the slides to our website at our earliest opportunity.

As a reminder, today's conference call contain certain projections and other forward-looking statements within the meanings of the Federal security Laws. The statements are subject to risk and uncertainties that may cause actual results to differ from those expressed or implied in these statements. Additional information on factors that could result -- that could cause results to differ is available on the Company's 10-K. We would ask that you review it and cautionary statements in our earnings release.

We have allotted approximately 30 minutes for Q&A end of the call and would ask that participants limit their questions to a primary question and a follow-up. I will now turn the call over to Todd.

Thank you, Scott, and thank you, everyone, for attending our earnings call. I'm very pleased with the progress we made this quarter. We generated positive free cash flow during the quarter while keeping production volumes essentially flat, especially crude oil. This was a testament to our ability to drive efficiencies across the Company in the face of a challenging oil market. This was our second full quarter as an independent company. We continued to protect our base production and our margins and delivered results that were in line with, or better than, the guidance we provided for the quarter.

Commodity prices improved modestly compared to the first quarter. However, we are still try to find an new normal for oil and natural gas prices and until prices are stabilized, we will be presented with the challenges that go along with increased volatility in the commodity markets. We are fortunate to have our low decline assets in the ability to moderate capital and operating costs as we move through this environment. These results, delivering positive cash flow by maintaining our recent production volumes, are due in part to the long-lived nature of our reserves. This will be apparent later on this call as we talk about performance.

Our low decline assets helped support a capital investment plan of about $600 million to $700 million annually. We believe this will enable us to sustain our crude production volumes at today's levels for each of the next three years or even longer. And we think we can do this while achieving and even overall lower level base decline rate, which will moderate and will continue through this -- some period into the future. We think this differentiates us from our peers.

As I look back to the priority items that we mentioned in our first-quarter earnings call, we noted CRC would focus on the balance sheet. Our balance sheet was built for $100 oil, so deleveraging remains our number-one priority. Today our net debt level has stabilized and we continue to advance our efforts to deleverage the balance sheet. We have several avenues to achieve our debt reduction targets, which I will touch on later. Our goal is to pay down $1.6 billion of our debt, with the first steps to be announced by the end of this year.

In the second quarter and the first half we achieved positive free cash flow before working capital, showing improvement from the end of last year and early this year. We anticipate we will continue to generate free cash flow for the remainder of the year. Our ability to live within our means and consistently generate positive free cash flow is a principle factor that differentiates us from nearly all of our peers.

Our second-quarter capital investment amount was below our guided level, due almost entirely to the capital efficiencies our operating teams have achieved. Additionally, we continued our keen focus on cutting cash operating cost. Even though commodity prices remained sluggish into the quarter, our cost-cutting initiatives have helped us to defend our cash margins.

While we have taken the steps to adjust to today's challenging environment we've been planting the seeds for a vigorous recovery and for longer-term growth, as I will discuss later in our review of our initiatives this past quarter. We have also continued are strong trend of reducing operating costs. I want to call out to your attention on one data point that illustrates our cost-cutting. Production cost in first half were $16.39 per BOE and this was down from $19.02 last year.

Beginning earlier this year, we redeployed portions of our workforce to focus on improved operational efficiency to build robust project pipeline. Some of the initiatives our teams of implemented include reducing cycle times, well equipment failure rates and nonproductive time and improving artificial lift. We have adjusted our contracted workforce to current activity levels. Importantly, throughout these efforts we continue to emphasize risk management, safety and environmentally sound practices in our operations.

A portion of the decrease in our operating cost has been as result of more efficient power usage and higher use of lower cost internally generated power. We also benefited from lower natural gas prices, which reduced the cost of steam generation from our steamfloods as well as the cost of electricity. We expect modest pressure on our operating cost in the third quarter from higher summer electricity rates and increased work-over and down-home maintenance activity that supports our base production.

Much of our success in reducing operating costs is the result of effective field management. Strong example of this can be seen our Elk Hills field. Our operating teams have been able to reduce cost on a per well and per BOE basis despite increasing produced water in total liquid volume, which is customary in a mature field. In addition, we see similar results when we take a look at our Wilmington Field. It is our experience that less than one-third of our cost our fixed and we take every effort to optimize production facilities and cost based on the current environment. You will hear more from Mark about why only one-third of our overall costs are fixed and how important that has already been and will be going forward.

Our second-quarter production was in line with the guidance we previously provided. Excluding the negative effect of over 3,000 BOE per day from higher prices on our production sharing contracts in Long Beach, our sequential quarterly production would have been essentially flat. Our base production continues to outperforms our estimated base decline of 15%, which includes historical downtime trends. Our second-quarter production of 161,000 BOE per day is largely due to lower decline rates of our conventional assets and our ongoing shift towards increasing steamflood and waterflood investments. The lower capital intensity of steamfloods and waterfloods will allow us to deliver flat to slightly higher oil production in 2015 over 2014 while investing significantly less than previous years. The 2015 capital budget is almost entirely focused on oil-weighted production. Further contributions to the reduction in the base decline have come from our record low downtime this year, a testament to the knowledge, tremendous effort and dedication of our workforce. In total, we continue to reiterate our production guidance that crude oil production will be flat to up over the 2014 average and total production will be flat to down slightly in 2015.

As we often speak of base declines, I believe it is beneficial to showcase how well our largest field, Elk Hills, is doing with respect to its decline rate. Here's a field where we have drilled over 2,500 wells, starting from the time our acquisition in 1998. However, we have continued to identify infield development locations plus had a significant exploration success in both conventional and unconventional reservoirs. Reflecting our capital discipline, we have elected not to have a drawing rig at Elk Hills since our launch, so we have observed its natural decline over the past eight months. The results have been impressive, with decline rates better than anticipated. On Slide 10, you should also note that the decline curve is flattening as Elk Hills transitions to secondary recovery. Our Elk Hills team continues to make great progress and operational efficiencies as highlighted earlier.

Our capital budget is focused on steamfloods and waterfloods in 2015 and we believe current front highlights both activity and successful results from one for larger steamflood projects. What attracts us to these types of projects as the modest capital investments that drive solid VCI returns. As shown on our associated slides, you can see that the 9% base decline in how we are able to ramp production with the consistent drilling program. As indicated, given our 800 plus remaining PUD locations, we expect to the ramp production for the next several years. As I said before, transitioning certain of our assets to steamflood and EUR project will flatten declines over time. We have developed life of field plans, including facility cost to optimize returns by identified and total resource and are maximizing production through our value recovery chain. We are proactively managing base production and new development drilling.

New wells for both steamfloods and waterfloods require modest capital and the associated facilities and work -- capital work-overs yield solid long-term full cycle returns. As we have shown in these two field examples we have predictable production base with low declines. This gives us the confidence in our capital planning and constructing our capital levels going forward. So if the current market conditions were to remain static for the foreseeable future, we believe we can maintain crude oil production relatively flat with approximately $600 million to $700 million annually for the next three or more years. We also would expect to achieve an lower overall base decline rate following that period. We live in a cyclical commodity environment and are planning our business around a mid-cycle case. We believed three years is reasonable timeframe and note it is longer than the 1986 trough for 50% recovery. As we have highlighted, we have the inventory to sustain CRC's production in growth far beyond this time horizon.

As I previously noted we have been driving efficiencies within our capital program. The resulting savings from reduced investments in the first half of the year will be considered for additional projects based our Value Creation Index focus process, including an increase in our work-over activity or deleveraging based on our conviction around commodity prices through the remainder of 2015. We believe using life of field analysis and our VCI approach to capital allocation for select projects ensure capital is invested in an efficient manner that will ultimately build value for shareholders. As I mentioned earlier, we are continuing to see nice capital efficiency gains in the first half. We're looking for more markets certainty before we reconsider the balance between directing capital towards our deleverage or activity levels going into 2016.

Taking advantage of lower activity levels, we are deploying a portion of our technical teams to grow our project pipeline. This effort is paying off as our teams are identify new projects with attractive returns, adding to our project inventory. An example of this can be seen in our Wilmington Field. Four years ago we had approximately 700 drilling locations. From 2011 through 2014, we have drilled approximately 500 wells but also added nearly 800 additional locations for our current inventory of nearly 1,000 drilling locations. These locations remain commercial locations today despite the price downturn.

This is just one example from our world-class resource base we are positioned to grow as prices normalize and more capital he comes available. This is a showcase of our most mature field. California is a major hydrocarbon basin, but it is still underdeveloped and under explored and provides a target rich environment for our experienced development and exploration teams. As we've said in the past, we have world-class stable and predictable fields, many of which keep growing with effective management.

The opportunities provided to CRC by our successful exploration program should also be highlighted. The recent exploration well in a structural play was originally completed in the deepest reservoir interval and delivered production of several hundred barrels of oil per day. We recently moved up hole to the second reservoir interval and have seen flow rates in excess of 750 barrels of oil per day. This was a naturally flowing conventional reservoir and has further behind pipe potential.

In summary, we have a primary and unconventional projects that are economic now and a large inventory of conventional development projects that are expected to be repeatable with low technical risk. However, we are choosing to live within our means and consequently, we are currently deferring many high return projects. We plan to increase future activity with our primary and unconventional opportunities when commodity prices are more favorable. We still have a large inventory of primary projects to drill, some of which remain economic even at $35 Brent oil. Not only do these projects provide solid economic production but also have the additional benefit of opening up future work-over and secondary recovery opportunities that can leverage existing infrastructure, thereby enhancing future returns.

On the unconventional side, we believe there is ample opportunity and work to be done. We have unconventional opportunities on about 650,000 surface acres. We have a good understanding in upper Monterey and leverage our learnings as we test the Kreyenhagen, Moreno, [Wheply] in lower Monterey shales. We receive waterborne base pricing, which is more in line with the Brent index for our realizations in the California markets. This is due to the fact that California imports most of its oil from overseas markets. In the recent past, we typically realized a crude price in low- to mid-90% range of Brent. As we previously discussed, the effects of the refinery events have dissipated and our differentials have begun to move back towards historical levels. We expect our differentials continue to normalize.

We ended the quarter with a net debt balance of approximately $6.5 billion, consistent with the end of the first quarter. We expect to exit 2015, excluding the results of any potential deleveraging initiatives, with a flat to slightly lower debt level at current commodity prices. We are taking advantage of the time afforded by our amended credit agreement to continue evaluating various deleveraging options. Our intent is to better align our capital structure for a more modest normalized commodity price environment. Our near-term target is to pay down $1.6 billion in debt, leaving $5 billion at the end of 2016.

We are pursuing numerous parallel paths and are in active discussions with a wide spectrum of players for potential deals. We are advancing these discussions with a focus on both upstream and midstream opportunities. I've already discussed the quality of our impressive set of upstream assets with opportunities to bring forward the value of these assets with cash and carry type deals.

In addition, our comprehensive midstream infrastructure across California, which includes numerous compression and pipeline assets, the state's largest gas processing facility and power generation facilities, provides an opportunity around infrastructure assets for potential monetization. We expect to achieve our deleveraging goal through multiple transactions which will accomplish our debt reduction goals or other strategic objectives and nothing should be read into the order of these announcements.

In July, the state of California completed several milestones in updating its well stimulation and hydraulic fracturing regulations under Senate Bill 4, or SB4, which are the most stringent of any oil and gas producing state. We have operated under the interim SB4 rules over the past 18 months, so we understand the requirements, which provides full public notification and specific permitting of well stimulation work, the monitoring of any potential usable groundwater near the permitted well. The final SB4 regulations took effect on July 1 and we expect these regulations to provide more predictable timing for permitting of well stimulation.

As I previously noted, the drought remains California's most important issue. Consistent with our approach and SB4, we are working proactively with state agencies to advance policies that will increase the use of reclaimed produced water while preserving disposal options. We are committed to helping alleviate the effects of the drought by focusing on three elements, recycling produced water directly into our operations, reducing the amount of fresh water we use, and increasing the amount of reclaimed produced water we supply to water districts in the San Joaquin Valley for agricultural irrigation. In 2014 we provided 2 billion gallons of reclaimed water to agriculture and we are expanding our role in addressing the California water situation in 2015 and beyond. I'd also like to add that we have a legacy of safe operations and are committed to working proactively with regulatory bodies in the communities throughout California.

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

Thanks, Todd. As Todd discussed, we continue to live within the means of our cash flow while keeping production essentially flat and near our record highs. I'm very pleased to underscore that we were free cash flow positive for the quarter.

Our second-quarter results were largely driven by higher production, particularly for oil, significantly lower production costs and lower exploration expense compared to the second quarter of 2014. The results also were affected by lower product prices. Crude oil prices in the second quarter rebounded slightly from first-quarter 2015 lows. The Brent index averaged $63.50 per barrel in the second quarter compared with $55.17 in the first quarter. As result, our realized price averaged $56.73 per barrel in a second quarter compared to $46.44 in Q1.

As Todd mentioned, the effects of the California market externalities are dissipating and our differentials have begun to move back toward historical levels. Our crude oil realizations for the second quarter were 89% of Brent compared with 84% sequentially. While crude oil prices improve, both NGL and natural gas prices declined slightly from the first quarter. Realized NGL prices averaged $20.47 per barrel for the second quarter, down from $21.55 in the first quarter. Natural gas price averaged $2.49 per Mcf for the second quarter, down from $2.84 per Mcf in Q1.

On a year-over-year basis, all second-quarter average commodity prices were significantly lower, pressured by excess supply. Realized crude oil prices were down 46% from $104.50 per barrel. NGL prices were down 58% from $49.08 per barrel and natural gas prices were down 45% from $4.52 per Mcf. Our crude oil price realization followed the weakness in Brent, which was 42% lower on a year-over-year basis. Additionally, our realized prices reflected higher differentials to Brent compared to historical averages, in large part from the refinery events that Todd cited earlier and that we noted in our last earnings call. The decrease in natural gas prices reflects the mild California weather in first half of the year leading to higher than normal storage in the California natural gas markets.

Turning our attention to a continued bright spot, production. Second-quarter 2015 crude oil production averaged 104,000 barrels per day. This represents a 7,000-barrel per day increase, or 7% on a year-over-year basis. On a sequential basis, second-quarter oil production was 4,000 barrels per day lower than the first quarter. However, I want to note that over 3,000 barrels of the decrease was the effect of the production sharing contracts in Long Beach caused by higher second-quarter crude prices. Excluding the effect of these production sharing contracts, our sequential quarterly oil production was essentially flat.

Second-quarter 2015 NGL production was flat compared with both year over year as well as sequential quarters. Second-quarter 2015 natural gas production declined 9 million cubic feet per day from the year-over-year quarter and 8 million cubic feet per day, or 3% sequentially. The decreases were expected as we focused our growing programs entirely on oil. This led to total oil and natural gas production of 161,000 barrels of oil equivalent per day in the second quarter compared with 156,000 in the prior-year period and 166,000 BOE per day in the first quarter of 2015. Excluding the production sharing contracts effects, total sequential quarterly production was essentially flat.

Our cost containment program continued to make progress in the second quarter. Production cost of $242 million, or $16.59 per BOE, for the second quarter of 2015 were significantly lower versus prior year period costs of $270 million, or $19.03 per BOE. This reflects a 13% reduction on a unit basis. The decreases came across the board, particularly in surface operations, well servicing efficiency and the energy use and was also aided by lower natural gas and power prices. Results were essentially flat on a sequential basis for first-quarter 2015 costs of $242 million, or $16.20 per BOE.

We believe we're capable of continuing to align our cost for the product price environment as we go forward. Overall, we believe less than one-third of our operating cost are fixed over the life cycle of our fields. As substantial majority of our near-term fixed cost become variable over the longer term, as they can be can be managed based on the field stage of life as well as operating characteristics. For example, portions of labor and material cost, energy, work-overs and maintenance expenditures can be relatively fixed over the near term. However, they are managed down as fields mature in a manner that correlates to production and commodity price levels.

Similarly, a certain amount of cost for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as a the production from certain areas matures, well count increases in daily per well production tends to drop. When this happens, such support costs can be reduced and consolidated over a higher number of wells, reducing cost per operating well.

Further, many of our other costs, such as property taxes and oil field services are variable and will respond to activity levels and tend to correlate with commodity prices. We actively manage our fields to optimize our margins and economic value. As a result, if we see economic growth in the field we work to accelerate activity and productive capacity. Similarly, if a field begins to approach the end of its economic life, we carefully manage down overall costs and work to extend the economic viability of the field.

During the second quarter, we recorded a charge of $10 million in part related to our rationalization efforts, which consisted of severance and early retirement costs. Excluding this charge, adjusted G&A for the second quarter and the first half of this year was comparable to prior-year periods. Taxes, other than on income, which consists largely of ad valorem taxes, greenhouse gas credits and production taxes, were $53 million in the second quarter compared to $55 million in both sequential and year-over-year quarters. Ad valorem taxes in California, as we've discussed, are based on commodity prices and are assessed annually on a midyear basis. As result, we expect these costs come down in the second half of year as noted in our guidance page.

Exploration expense declined on both a year-over-year and sequential basis. Second-quarter 2015 exploration expense was $7 million compared with $17 million in the prior quarter and $15 million in the prior-year period. The declines were due to our reduced drilling activity. Interest expense and a second quarter amounted to $83 million associated with the debt we incurred in connection with the spinoff in the fourth quarter of 2014. The change over the prior quarter was attributable to lower capital investment leading to lower capitalized interest. As result of these factors we ended the second quarter of 2015 with an adjusted net loss of $51 million, or a loss of $0.13 per diluted share. This compares with an adjusted net loss of $97 million, or a loss of $0.25 per diluted share, for the first quarter and adjusted net income of $246 million, or $0.63 per diluted share, for the prior-year period.

The reported net loss for the second quarter was $68 million, or a loss of $0.18 per diluted share. Hedge related expenses of $17 million and other infrequent charges of $11 million, primarily consisting of severance and early retirement cost net of income taxes, accounted for the difference between the adjusted and reported loss in the current quarter. Second-quarter adjusted EBITDAX registered $270 million and cash flow below -- excuse me, before working capital changes was $166 million. EBITDAX was $72 million higher than the first quarter but $457 million lower than the last year second quarter, due largely to lower commodity prices, offset in part by an improvement in margins. Our EBITDAX margin increased to 43% in the second quarter from 36% in the first quarter. Adjusted EBITDAX for the first six months of 2015 was $468 million compared to $1.4 billion for the same period in 2014.

Our capital investment amounted to $95 million during the second quarter, which was $38 million lower than the prior quarter, due largely to the efficiencies that Todd discussed. I want to again emphasize that second-quarter capital investment was within our operating cash flow. Our drilling rig count for the current quarter remained unchanged at three rigs but delivered more wells than we planned. At the six-month point, our investments have totaled $228 million, or 52% of our $440 million capital plan for 2015, which was front-end loaded. As result, we believe we are well on track to stay within our capital investment target for the full year.

Our net debt decreased slightly from the first quarter to approximate $6.5 billion. We continue to approach our deleveraging efforts in a consistent fashion with thoughtful consideration of a number of opportunities that allow us to protect the NAV of our overall portfolio. On the hedging front, we continue to be opportunistic in the face of a challenging strip commodity price. To summarize our recent activity, we've added an incremental Brent crude oil hedge for the fourth quarter and initiated a small crude oil hedge for 2016. Additionally, we entered into several gas contracts for the second half of 2015. We provide more specific details on our updated hedging activity in our earnings release.

Our teams continued to take the proactive steps necessary to reduce our cash costs and enhance our origins. We are cognizant of the operational efficiencies being gained in our capital investments and are carefully balancing deleveraging through cash flow versus increasing activity into 2016. Please note that we have provided key third-quarter 2015 guidance information in the attachments to our earnings release. I will be happy to take any questions you may have on that information and on other aspects of our results during the Q&A portion of our call.

I will now turn it back over to Todd.

Thank you, Mark. In closing, as we significantly reduced our capital program this year, I challenged our organization to focus on base declines, reduce cost and build our inventory of attractive projects. Our staff has done an excellent job and we continue to execute and deliver our strategy.

Going forward, we believe there are opportunities to drive further efficiencies and better align our organization in this current environment, while still protecting our base rate of production. I'd like to emphasize the tremendous versatility and optionality within what is truly superb portfolio assets in terms of geology, play types, drive mechanisms and hydrocarbon exposure. This portfolio allows us to flex different elements of our asset base in conjunction with market conditions to provide economic production throughout the commodity price cycle. Furthermore, our continued focus on building our inventory has revealed a number of future government opportunities.

California is an under-explored and underdeveloped resource basin. Many have heard me speak of California as the land that time forgot in the regard to industry technology. This provides us with tremendous opportunity over the long-term. However, our first priority is to de-lever. We expect that as we de-lever the balance sheet, our stockholders will directly benefit. We believe that as we continue to execute our strategy, the market will recognize uniqueness of our low decline portfolio and the low capital intensity. We believe the premium received for crude oil resulting from being and a Brent-based waterborne market will benefit us as we move through the price cycle. I believe we provide many avenues for investors to invest both in the near term and longer.

As Scott noted, we will be hosting an Analyst and Investor site tour on October 12 to 14 and I would like to encourage our investors to attend or listen to the webcast. We expect at that time to provide additional information on waterfloods and steamfloods and provide a close-up view of our two flagship assets, Elk Hills and Wilmington. I know there's a thirst for more knowledge on these topics because based on early responses, we already have a packed house, which we expect to have to restrict due to safety and logistical considerations.

This concludes our remarks and we now welcome your questions.

(Operator Instructions)

Doug Leggate, Bank of America Merrill Lynch.

Good afternoon, everybody. Todd, I understand that there's only so much you can tell us about the deleveraging process, but obviously, it is pretty key to folks' perception about your ability to achieve some meaningful debt reduction. So is there any color in terms of the progress you've made since the last call to give us confidence that you can indeed confirm a meaningful enough or materially enough deal before the end of the year and maybe frame the order of magnitude as to what you think that would need to be to meet your criteria of impacting the balance sheet? I've got a follow-up, please.

Yes, I think if it wants to meaningful it would probably have to be hundreds of millions of dollars to be meaningful. So we would hope to have at least announced one or two deals by year end, if not possibly closed. But as you know, as you pursue these opportunities, the level of legal complex and the difficulty of getting from signing to closing in some cases takes longer than you ever might anticipate. I would say at this point in time, I believe we are on track to do one or more or many things going forward, possibly by year end if you are being opportunistic looking at everything. If you think pessimistically and that the lawyers need more fees, you are going to go into an early next year before you might close. But there's no reason to be less opportunistic or optimistic at this point in time. I think from my standpoint, I'm actually more optimistic as we move through all these different process we are looking at.

Without getting into specifics, Todd, do you have things on the table right now that are progressing to the point where you're going to put them in front of you Board or are you not there yet?

We had Board meetings over the last few days and we briefed our Board on more than a handful of the opportunities and we only talked about the material ones. I'd say material being hundreds of millions dollars, again. This is -- clearly, we're on path to execute one or more of these by year end and at least have them signed up. I think at this point in time, we didn't ask for their approval to proceed but they are well aware what we want to do because we are getting there. You can have one as early as a month or two or as late as the end of the year. It's just timing. Again, deals don't always go on any particular timeframe.

Got it. My follow-up is really on cash flow. Maybe for Mark. Mark, there is still a -- it looks like there's still about a $47 million to $49 million working capital burn this quarter, which I think you had signaled last quarter was a carryover from, I guess, what was going on at Occidental. What do you see going forward in the second half of it here in terms of working capital burn? I will leave it there. Thank you.

Doug, I think we're going to be pretty flat with respect to working capital changes move through the remainder of the year.

Okay. That's all I needed. Thanks, guys.

Evan Calio, Morgan Stanley.

Good evening, guys. The color on the Wilmington inventory commerciality is helpful. I know it is one of your stronger assets. Can you share any other breakeven color with, I guess, the balance of 80,000 locations or 12,000 X unconventionals, just to dimension the economics of that inventory?

If you are talking about Wellington, it is unique in many ways. It's third largest field to be discovered in North America, but it is got a production sharing contract associated with it. That dampens the impact of economics. It's much more economic as you move down the chain here and we've gone through it a few times but it is about as advantageous a PSE as you can have relative to what you might see in some foreign countries and works very well for us. Again, this is our most mature asset, too.

We hinted in our -- in my remarks talking about we have projects that are economic down to $35 [Brent.] But I think if you talk about drive mechanism, I think I can break those down for you a little bit. If you think about steamfloods, again steamfloods is more a function of oil and natural gas prices, so those that can be economic as long as you talk about oil prices being more than six times natural gas, as a general rule of thumb. There are some other circumstances, steam-oil ration anything else, but those -- when you have natural gas price where it is and oil where it is, these are economic for a long time as you go down the commodity cycle if it turns worse from here.

Our conventional opportunity set is all over the place because we have everything from conventional dry gas to conventional oil opportunities, so I think that, that is the whole gamut of potential opportunity set. When you look at our waterflood assets, again, these are some of the strongest economics we've shared with you before. Our Mt. Poso project, that's economic well into the Brent and a very low price profile, probably in the high $30s, low $40s, a lot of our waterfloods, Wilmington being the most mature one.

When you think about our unconventional opportunity set, really until Brent starts getting into the high $60s I don't think the shale type opportunity set jumps out at you but in California we have a lot of, from the unconventional side, tights sands and those opportunities are as competitive as some of our waterfloods and steamfloods currently; and probably one of the next projects up in the pipeline, so gives you a little bit of the flavor. I think conventionals are goes all over the place because you are talking about different things. But I think really thinking about shale development, it is probably still in -- Brent would have been the upper $60s to really have that be competitive within our portfolio of opportunities.

Great. As far as that relates to the monetizations or JV discussions? Is the entire upstream [coming] open for potential offers or is it more limited to one asset set versus the other? Would you be willing to monetize some of the most economic resource?

As we said, nothing's off the table. We are looking at everything. But if you want to break into two buckets, midstream and upstream, upstream part of our plan all along was to bring forward value. We have such a long portfolio and a huge amount of resource, so part of that plan is really to bring in partners on the development and the exploration side. So exploration is something that you tone back in this environment but there's an ample amount of people that are very interested and being our partner. Again, a lot of these are things that under oxy we might have sole risked, but now it makes sense from a risking standpoint to have a partner and accelerate some of this exploration forward.

On the development side, we looked at everything and anything. We have people interested, from dry gas in the Sac basin down to every type of opportunity you might think of throughout the San Joaquin, Ventura, and LA basin. I think the only thing you would argue that would be off the table would be the Wilmington property simply because that's in a production sharing agreement and that would be too difficult to try to bring in a partner. But everything else, I think, we are willing to entertain but it obviously has to be accretive to our value and bring in the right type of partner for us.

That's great. If I can just squeeze one more question in and go back to the maintenance CapEx, the discussion. I know you gave the three-year average, $600 million to $700 million disclosure more recently and that excludes the lower 2015 number. Yet if necessary, how low can you take that figure in 2016 and how quickly is there that kind of catch up CapEx to move you back into that average range?

I think what we are try to give you there was really a longer-term three-plus years type -- we just targeted three year simply because that was longer than the first big price trough in the 1986. But if we had to keep oil production flat next year, we're talking about just 2016, about $500 million, if we had to, we could do that. Obviously, we'd be probably modestly down on BOE basis, but we feel like we could probably keep oil production flat next year at $500 million. There probably would be some catch-up in prior years, but we feel really good about that $600 million to $700 million number as we've done our life of field plans out three years and beyond that.

Great. I will leave it there. Thanks, guys.

Tarek Hamid, JPMorgan.

Good afternoon. As you look at -- you talk about the $1.6 billion debt reduction target, as you think through some of the potential projects you've talked about, do you really feel more like you are headed down the cash and carry route more than the true sale route? Trying to get a sense of how we should be thinking about this rolling into 2016 in terms of the impact on the asset base and the cost structure?

We're moving down every type of path. I think we have ruled anything out. Some things look more promising than others. I would say there's a plethora of cash and carry both development and exploration type joint ventures out there. It is something we are actively in discussions with numerous folks about. But yes, I think that there's nothing we've ruled out, but again, it is a question of value and we got to understand how it affects our operations on a long-term basis. Again, I don't think we've, at this point, ruled out anything.

Then given your broader goals on debt reduction, any thoughts towards proactively trying to repurchase bonds, given the discount they are trading at? Or is that something that you are not ready to go forward with yet?

If we had a different capital structure, clearly it would be something you would entertain, but at this point in time, with where we are sitting, that is not something we look at doing. Mark can give more clarity on that.

It is Mark here. The senior bank facilities, as well as the term bank facility, has no prepayment penalty associated with it, so it is ideally suited for the application of proceeds of any of these transactions and that's typically what we will look toward.

It cannot be opportunistic if that situation presented itself with in the future with us having a bunch -- if we had cash to do something like that.

Okay. Just last one, detail question. $47 million of other add back in the adjusted EBITDA reconciliation, any color on what that is? Is that some of the derivative gains? Just trying to understand what is that sizable portion of the number this quarter?

Non-cash items, derivatives, one-off items.

There's severance and early retirements in there, too.

Just a smorgasbord of stuff?

Yes.

Okay. Thank you very much. That's helpful.

Brian Singer, Goldman Sachs.

Thank you. Good afternoon. On slide 11, you mention that your decline rate is pretty low. I assume production would likely plateau if drilling stopped. Can you just reconcile the two together? If that is in reference to production, what would drive without drilling the production to plateau? Is it a pressure situation or wells behind pipe, et cetera?

When you think about steamfloods as you continue to keep them up, they plateau eventually and then they -- before they start to decline. So they are going to incline, then they are going to plateau, then decline. I think the other thing that you've got to think about here overall, and I think it gets lost, is what the work-over rigs do for you in these kind of fields with this amount of stack pay and behind pipe potential, and that is something I think gets lost on everyone. The work-over rig creates much more value for us than any drilling rig typically in this type of environment, because the bang for the buck, there is no better bang for the buck. Our highest PCI projects are all with a work-over rig and it is something that I think gets lost the shuffle here because people are so focused on the drilling model as opposed to the ability to work in a stack pay environment utilizing a work-over rig.

The work-over rig would be part of the $500 million of maintenance capital, or that would be above and beyond that?

Some of it will be expense or work-over, depending on whether it is -- what kind of activity that's going on.

But yes, Brian, you are right. Capital work-overs would be in that $500 million number.

Okay. Great. Then Mark or Todd, how important is one-time debt reduction versus ongoing debt reduction? It goes to how willing are you to take your ongoing cost structure higher and free cash flow lower in exchange for debt reduction now versus stay closer to maintenance capital or below that and pay down debt via free cash flow?

We have to think about, especially since your compatriots there, your firm believe lower for longer. I think we have to plan on lower for longer and I think we have to put ourselves in position as a Company to be prepared for that. And so from our standpoint, as Mark alluded, the debt that's pre-payable is our term loan and our facility and I think once we get into a position, we'd like to manage the balance sheet throughout the cycle. If you talk mid-cycle, as we've told you many times, at two times. We are long ways from that at this point in time but we are going to work ourselves to that and we get in position where we start deploying our free cash flow that way, it will be something that we will definitely look at doing.

As we continue the investment profile we have, we're increasing our oil percentage and increasing our cash flow even in this price environment as we come in oilier, I think that those opportunities will even present itself on a small scale. But because we have this credit amendment through next year, we have a little bit of need, desire, to want to pay down that debt to preserve our optionality and flexibility as an enterprise.

Great, thank you.

Paul Sankey, Wolfe Research.

Hi, good afternoon, guys. A couple of slightly itsy-bitsy questions, if you don't mind. You said about the $95 million of CapEx it came down on cost savings and other initiatives. You've guided to it going back up again in Q3. Why would that be?

I think we're going to add a little bit of capital work-overs in the third quarter and that's the biggest part of it and it's just activity driven.

Okay. I was just wondering because you'd assume that cost would continue to fall, but maybe you didn't mention it in very complete comments before, but it is $105 million to $115 million guidance. I'm aware that it is within the overall annual guidance that you've given. I just wondered why it would actually be going back up again.

Paul, if you think about it, the run rate of our rig fleet has not changed. We see some opportunities to create value even in this environment on the capital work-over side, like Todd said, so when you tear apart the numbers it is a slight uptick quarter over quarter in terms of capital work-overs.

I cannot over emphasize the capital work-overs. These are all things that have VCIs of [two, three] or plus that, these are, some cases [four or five], so this is something that incredible value creation and that's why we want to jump on these and we have this opportunities.

Understood. I guess you got to accelerate a bit as well to exit the year and allow yourselves to stay going flat going forward, right? Does that make sense?

Yes, managing the base. Yes, we are going to be doing that proactively.

Is a possible -- again, sorry to be itsy-bitsy but can you give any sort of break down as the CapEx by basin?

Hold on. Basically, from a drilling perspective it is two-thirds San Joaquin, one-third, LA Basin and the rest of the breakdown on a percentage basis -- the other ones are not meaningful relative to those two if you look at it on a quarterly basis.

Sure. You given us some great disclosures here and gone through it some detail and I apologize to be grinding around in these details. One thing that struck me is that you have had a positive G&A expense on retirement and severance, $10 million positive, but I'd never heard of a positive retirement and severance. I'm not automatically saying it would be an expense, I wondered how come it was positive?

Adjusted EBITDAX and you are talking about pension plan, early retirees, some of them and some early retirees around the Company?

Yes. In my experience I've never seen a positive one. I just wondered, did someone pay to leave?

It is not positive. Maybe it is a bad typo or something but it is an add back to the expense.

Add back to the expense. Am I totally confused? It is a negative, then?

Hang on just a moment.

(Multiple speakers) It is a negative.

The GAAP G&A to the adjusted G&A.

Negative, to add back to adjusted G&A or EBITDAX you've got to add --

I apologize for wasting everybody's time. I got confused on that. I think you've handled the other stuff pretty well, actually, as far as I'm concerned. The big picture, obviously, remains that you believe that even at the new strip that we are now talking about, because obviously this was a $60 quarter. We are were now down, as you know, to below $45. How does that relate to the long-term $600 million to $700 million that you are talking about given that we've come down another -- it feels like another $15 lower per barrel against the $600 million to $700 million that you've talked about to stay flat. Where do we sit at the current price of oil? I will leave it there. Thanks.

Yes, I think the $600 million or $700 million doesn't change as a number overall when we talked about long-term. If you are thinking about the current price profile, as we are coming into this year we had a very similar look at that point in time and you saw approximately where our capital was. We've [become] oilier in the meantime, generated more free cash so if you thought about it in that perspective, it drives you towards the $500 million that we talked about. But the bottom line is, as we've said numerous times, is we will stay within our cash flow. You are not going to outspend our cash flow.

Can you remind us, you do have a sensitivity, I believe for every $10 change in your --

Yes, it is on the guidance page of the earnings release there, Paul.

$7 million per $1 change in Brent.

Yes, right. Paul, back your earlier question, you were probably looking at page 9 in the earnings release, at the top of the page there, where we talk about adjusted general and administrative expenses, you see G&A as $85 million, there's early retirement and severance cost, you seeing a negative $10 million there?

Yes, on the next page. I'm being -- doesn't matter. I think I've got it.

It's just an adjustment, adjust out for one-time -- (Multiple speakers)

I think later on appears a positive and I got my head spun, so let's leave it. That's great. I will leave it there. Thanks a lot.

James Spicer, Wells Fargo.

Hi, good afternoon, everyone. Your credit facility becomes secured, I believe, your corporate family rating is downgraded to either [Ba3] or BB-minus by the agencies. I guess first of all, have you had any conversations with the agencies? Do you have a sense as to how likely it is for something like this for this to happen and if it did, can you just discuss what the real impact to you would be of having a secure facility?

First, when the credit facility was put in place back last year, it contemplated the whole concept of security and the bonds were put in place with the concept of security, baskets were structured, et cetera. As opposed to most other E&P credit facilities, this facility contemplated not only the upside but also downside. So it is very well thought out very, well laid out, very well documented within the credit facility, what actually occurs. We have ongoing dialogue with the rating agencies.

We visited with Moody's as well as S&P. The most recent ratings action was by S&P. They reaffirmed the rating. They put us on a negative watch. Our discussions with them, we don't expect them to change anything for some time and I think they clarified within their press release what things would need to occur for there to be more formalized ratings downgrade. Based on our discussions, I think we feel pretty confident where we are with the rating agencies.

And if you did get -- if bar and base did go secured, I assume that it will be subject to the re-determination process?

Based on the amendment, we currently have -- we currently have, what I refer to as a PV9 test, currently and so if we were to go secured, that's basically that same kind of concept going forward with respect to a borrowing base period underneath the facility. And it is an annual determination. It is not a six-month determination.

Okay. Great. That's helpful. (Multiple speakers)

For any other detail I would encourage you to look at the actual document. It is out there in file.

Yes, I understand. Another question I had, you talked about the $95 million CapEx spend during the quarter. On the cash flow disclosure in your press release, there's $127 million cash from investing activities. What was the incremental difference between the $95 million and the $127 million?

It is accrual differences, James.

Okay, just accrual. All right. Then finally here, can you just comment a little bit more on where you guys stand in terms of hedging? I saw you locked in a crude swap at over $72 for 2016. I don't remember the curve being that high. Was there a premium associated with that or can you just maybe talk about that structure and then how you feel about things given the commodity price outlook today.

From hedging standpoint, again, we look to be opportunistic. We were spun off into a very difficult environment. If we talk about -- we were near the bottom of the cycle, if not, we're sitting there now. We looked for any days and we monitored it regularly to look at opportunities where we could hedge our production and we continue to be opportunistic and look at ways to protect our investments and protect our cash flow stream.

This is something that we wish we would've been able to pull off more. There was actually a chance for us to pull off more in that hedge and it got pulled back after only doing 2,000 barrels but we were trying to do more at that time. So this is something -- like I say, we continue to try to be an opportunistic. Right now it is a difficult environment. You look at the curve, it is pretty flat for a few years. But it is something that we look to be, again, opportunistic on.

Then just terms of the structure on that, 2016, was that just a straight swap? Was there any deferred premium associated with that or anything?

There was no premium. It was a straight swap.

James, this is Mark. As Todd said, no premium associated with it. It is a straight swap, 2,000 barrels a day at $72.[05]

Okay. Great, thanks a lot guys.

Sean Sneeden, Oppenheimer.

Hi. Thank you for fitting me in here. Most of my questions were answered, but maybe, Todd, for you. I know you guys talked a lot about JV potentials both on the upstream and midstream side, and clearly, I'm sure you guys have been cognizant of the sheer amount of private equity money that's been raised on the sidelines here to try to target oil and gas. Is there anything in particular, speaking mostly about the upstream stuff you are marketing or thinking about, is there anything that would separate your asset package versus some of the stuff coming out in the market at this point, at least in your mind?

I think it is a classic case of the California story we've been telling. It is unique opportunity set. These type of assets we have typically reside in the super major. The exploration portfolio -- you won't see this type of exploration portfolio in typically in North America. You are going to have to go to somewhere, some exotic location, where you need armed forces to protect you to drill, to see these type of opportunities. I think we have everybody of every size from both private equity, private companies, other companies involved, so I think there's a whole suite -- and you are right, there's a lot of money that looking to invest on this from the sidelines, but I think the upstream market is really driven by our predictable low declines, oil-focused portfolio.

Sure. With that in mind, would the ideal structure be mainly focused on those type of lower decline rate opportunities versus more on the unconventional exploratory side? How are you guys thinking about that first step?

If you think about, we have people that are working at both exploration and development, but here on the development side, there's people interested in dry gas. There's people interested in the shales, in certain types of shelves, or certain -- one of the shales. There's people interested in conventional opportunities, people interested in heavy oil. It is a whole suite of opportunities. I would say there is more interested in more conventional opportunities then unconventional at this point time, but it doesn't mean we still don't have people interested in that stuff.

Okay, I appreciate that. Then maybe just one housekeeping here for you or Mark. When you guys talk about a deleveraging opportunity, I just want to make sure that I'm understanding what do you mean by that correctly. Are you thinking about that as a lowering your overall debt-to-EBITDA metric or just thinking about that in terms of paying down debt?

I think it is a little bit of both. You are trying to ultimately get to the debt-to-EBITDA ratio down, but it is also paying down our $1.6 billion of debt and doing so through these different transactions.

Okay. Fair enough. Thank you very much.

John Herrlin of Societe Generale.

Hi, guys, most things have been asked, given the stream of consciousness questions. Field utilization rates, how good were you at minimizing downtime during the quarter? Maximizing well output?

I think we are at record downtime -- I mean uptime, I want to say. Record low amount of downtime or record uptime if you want to think about it, both our northern and southern operations. It is been -- year over year it has been a 25% reduction overall, if you look at it that way.

Okay. That's fine. Next one for me is deleveraging. You've talked a lot about it, you've got a lot of questions on it. Do you have a data room process going? How exactly are you approaching these monetizations? I'm just curious.

We actually have numerous data rooms in parallel on all these different opportunities, from midstream potential monetizations, uptrading monetizations. We have a bunch of different data rooms going on and in some cases, site visits.

Okay. Great, that's it for me. Thank you.

Jeff Davies, TPH Asset Management.

Thanks for taking the questions. Just a couple quick ones. On the hedging, just want to hit on that again, just what the philosophy is. Is there a systematic program? I guess I pulled up the Brent calendar 2016 strip and there was about three weeks it was above $72 -- above $70, excuse me. So to just throw on 2,000 barrels a day on a production base of 100,000 barrels a day, doesn't feel like there was really much in the way of being aggressive there when you had the chance. Just curious how systematic that program is?

It's very systematic. We are monitoring it literally daily and the whole spectrum weekly and we are trying to look at things going forward. Again, just because your screen says one thing, the amount that you can actually pull off in liquidity in depth of the market is different and we found that out ourselves as we tried to go in there and do a much bigger hedge then 2,000 and we were not able to pull off more than 2,000 at that point in time. So again, just because your screen says it, doesn't mean you can actually action that.

Okay. And some of your peers have disclosed their PV-10s that strip here as of quarter end? Are you willing to give that? I guess I see it on slide 15, the PV-10 debt coverage. Is that something you will disclose?

No. We are unsecured on our credit facility. We'll do it at year end in the regular process as we shift our reserves to being audited by a third party away from the process review that occurred at our former parent.

Thank you.

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

Thanks, everyone, and hopefully we will see you out here in October at Elk Hills/ Wilmington and hopefully we will be the middle of an El Nino and help the water situation in the state. Thanks again.

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