Earnings Call: Q4 2014

Jan 29, 2015

Good morning, and welcome to the Occidental Petroleum Corporation 4th Quarter Earnings Conference Call. All participants will be in a listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Chris Degner. Mr. Degner, please go ahead. Thank you, Emily. Good morning, everyone, and thank you for participating in Occidental Petroleum's Q4 2014 conference call. On the call with us today are Steve Chazen, Oxy's President and Chief Executive Officer Chris Stavros, Chief Financial Officer Vicki Hollub, President Oil and Gas in the Americas Willie Chang, Executive Vice President of Operations and Sandy Lowe, President of our International Oil and Gas Operations. In just a moment, I will turn the call over to our CEO, Steve Chazen, who will review our achievements in 2014 and provide an outlook for 2015. Our CFO, Chris Davros will review our financial and operating results for the Q4 and also provide guidance for 2015. Then Willie Chang will review our 2015 capital plan followed by Vicki Hollub, who will provide an update of our activities in the Permian Basin. As a reminder, today's conference call contains certain projections and other forward looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on factors that could cause results to differ is available on the company's most recent Form 10 ks. Our Q4 2014 earnings press release and the Investor Relations supplemental schedules, our non GAAP to GAAP reconciliations and the conference call presentation slides can be downloaded off of our website at www.oxy.com. I'll now turn the call over to Steve Chasen. Steve, please go ahead. Thanks, Chris. I'd like to start with some highlights from our accomplishments in the past year. We executed many of our strategic initiatives including the spin off of California Resources, the sale of our Yucatan Gas properties, BridgeTex Pipeline and PAGP units. At the end of the year, our cash balance of $7,800,000,000 dollars exceeded our total debt of $6,800,000,000 We grew our domestic oil production by 11,000 barrels a day over 20 13 to 181,000 a day. We grew our Permian resources production from 65,000 13 to 75000 equivalent barrels a day last this year. The 2,004 capital program added 395,000,000 barrels of proved reserves replacement ratio of 181 percent before dispositions. Our costs incurred with these reserve additions were about 6,700,000,000 resulted in an apparent finding development cost of under $17 a BOE. We added 363,000,000 barrels of liquid proved reserves, replacement ratio of 2 23 percent before dispositions. We completed the Elhosin gas project on budget and on time, which started production in early January. A few comments about the macro environment, The confluence of U. S. Supply growth, weaker Asian demand and extreme currency movements have led to significant decline in product prices. Our company is resilient and built to weather price shocks typical to this industry. Obviously, we have the financial resource to continue drilling at the 2,004 rate. However, the current service cost company's cost structure is more reflective of $100 oil price environment rather than the $50 environment we have today. While service companies have offered modest price reductions, they still do not reflect the current reality. We're focused on reducing our costs, which include renegotiating our supplier contracts that are not reflective of weaker oil prices. We expect these efforts to result in a reduction in the cost of executing our capital program as well as reducing our operating expense. It makes little sense for us to push production so as to sell our oil at $50 or less. We have I'd like to just talk about briefly about the impairments. Have virtually eliminated our capital spending in the Williston Basin on domestic gas properties in Bahrain and the Jossen Oil Sands projects as these have unacceptable returns in the current price environment. As a result of a thorough portfolio review, we have reduced the carrying value of the assets in the areas where we are minimizing development activity. This resulted in an after tax charge of $5,100,000,000 These charges did not affect our cash position. Chris will detail the charges. Our policy has been and will continue to be to write down assets to approximately fair market value when we believe that when we believe that the impairment is other than temporary. In 2015, we will focus our capital spending on the core areas we operate principally the Permian Basin. Our capital budget is $5,800,000,000 which is a 33% decline from 2014. 2 thirds of the capital budget will be allocated to maintenance capital and 1 third allocated to growth capital. Through the start up of several long term projects notably the Al Hosan Gas project in the Brits Edge pipeline, our 2015 15 capital program was on course to decline before the recent fall in product prices. Our capital run rate in the first quarter will be higher than the $5,800,000,000 level and will decline all year unless product prices significantly improve. Given our large acreage position and deep inventory, we have the flexibility to defer drilling and appraisal activity. Although we will likely outspend our cash flow during the first half of the year, we expect that by the end of our end of the year, our operating cash flow will cover our capital expenditures and dividend payments, assuming a recovery to $60 oil price environment. Willie Chang will provide more details on our capital program later in the call. Despite the lower capital program, we expect to deliver 6% to 10% annual production growth in 2015, driven by the start up of the El Hozan Gas Projects and the focused development program we will run the Permian Resources business. In the United States, we expect oil production to grow about 6%, partially offset by declines in NGLs and natural gas production. Vicki Hall will provide further details on the outlook for the U. S. Oil and gas business. We had a successful year in growing the company's reserve base by adding substantially more reserves than we produced. Companywide, we replaced 174 percent of our production before asset sales. We ended the year based on a preliminary estimate with about 2,800,000,000 BOEs of reserves. Through our organic development program, we placed 181 percent of our production. This estimate excludes acquisitions, asset sales and revisions of prior period estimates. Our reserve replacement ratio for liquids from all categories before asset sales was 2 23%. This reflects our emphasis on oil drilling. Our total costs incurred relate to the reserve additions for the year on a preliminary basis of approximately $8,300,000,000 As a result of our organic development program, we estimate an apparent finding cost of under $17 a barrel. Our 2,004 acquisitions were approximately $1,600,000,000 and we booked a conservative amount of proved developed reserves. We expect to add incremental reserves as we exploit this acreage. At the end of the year, we estimate that 76% of our total proved reserves were liquids increasing from 71% in 2013. Of the total reserves about 71% were proved developed reserves compared to 70% in 2013. Over the past several years, we have built a large portfolio of growth oriented assets in the United States. In 2014, we spent a larger proportion of our investment dollars on these resources. Our organic reserve replacement for the year reflects the positive results of the appraisal and development efforts capitalizing on the large portfolio built over time. In the United States, we replaced 2 66% of our production before asset sales. We ended the year based on a preliminary estimate with about 1.8 BOE of reserves. Our organic development program replaced 2 86 percent of our production. The estimate excludes acquisitions, asset sales and revisions of prior estimates. Our reserve replacement ratio for liquids from all categories before asset sales was 306%. Our total costs incurred related to domestic reserve additions for the year on a preliminary basis were approximately 5,700,000,000 dollars As a result of our organic development program, we estimate an apparent finding development cost of about $12 a BOE. Through the success of our drilling program and capital efficiency initiatives, we have lowered our finding development costs over recent years. As a result, we expect our DD and A expense to be approximately $15 a barrel in 20.15, a decrease from $17 a barrel in 20.14. This is consistent with our expectations of DD and A rate of growth should flatten out as recent investments come online and finding and development costs come down. The success of our organic reserve additions and the efficiencies we have achieved in our operation demonstrate the significant progress we have made in turning the company into competitive domestic producer. Through initiative, we have raised enough cash to exceed our debt at year end. Slide 14 outlines the priorities of our use of cash. It's the same slide we have shown for at least a decade. After spending on maintenance capital, the top priority for our cash flow is to continue to increase the dividend. We've increased the dividend for 12 consecutive years and are committed to annual increases. Our remaining cash flow will be allocated to growth capital, share repurchases and acquisitions. In 2014, we repurchased $2,500,000 of shares. We have approximately 71,000,000 shares remaining under our current authorization. We will continue to repurchase shares subject to stock price and market conditions and expect to ultimately repurchase the entire amount. Now I'll turn the call over to Chris Stavros for a review of our results. Thanks, Steve, and good morning, everyone. Oxy completed the spin off of California Resources at the end of November. Accordingly, we have reclassified the financial and operational results to discontinued operations for our core results disclosure. As such, our Q4 2014 core income excludes all of the California results and income on a reported basis includes 2 months of California results. Total year 2014 results on a reported basis include 11 months contribution from the California operations classified as discontinued. We generated core income of $560,000,000 for the Q4 2014 resulting in diluted earnings per share of $0.72 a decrease from both the year ago quarter and the Q3 of 2014. The decline in core earnings was attributable mainly to sharply lower realized oil prices on our worldwide production. Net results for the quarter were a loss of $3,400,000,000 or $4.41 per diluted share. In accordance with the successful efforts method of accounting, which Oxy follows, we review our proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of the oil and gas properties may not be adequately recovered such as when there's a significant drop in the futures price curve. Under the successful efforts method, if an oil and gas property's estimated future net cash flows are not sufficient to recover its carrying amount using the period end futures curve, an impairment charge must be recorded. As of December 31, Oxy recorded property impairments due to the fall in the futures curve for oil as of that date. The 2014 Q4 includes after tax non core net charges of $4,000,000,000 Approximately $2,700,000,000 of this was a result of the sharp decline in the year end WTI price curve that affected our domestic properties. Most notably, this included a charge of $1,700,000,000 in the Williston Basin, dollars 600,000,000 related to our gas and gas condensate assets, $350,000,000 for other domestic acreage. Foreign impairments amounted to $1,100,000,000 principally related to our operations in Bahrain. Additional charges included $700,000,000 for our interest in the Josslyn Oil Sands project and a $550,000,000 mark to market adjustment for the carrying value related to our remaining 19% interest in California Resources. The 4th quarter also included after tax gains of $900,000,000 from the sale of a portion of our investment in the Plains All American Pipeline GP and $400,000,000 from the sale of our 50% interest in the BridgeTex pipeline. We continued our strong domestic oil production growth and achieved a year over year quarterly production increase of 19,000 BOE per day or about 11% led by our Permian Resources assets. We also purchased 4,800,000 shares of our stock during the 4th quarter and ended the period with 7,800,000,000 sheet. In oil and gas, our core after tax earnings for the Q4 of 2014 were $368,000,000 540 $9,000,000 lower than the Q3 of this year and $731,000,000 lower than last year's Q4. For the Q4 of 2014, total company oil and gas production volumes from continuing operations averaged 616,000 BOE per day, an increase of 21,000 BOE per day in daily production from the 3rd quarter and 41,000 BOE per day from the same period a year ago. This excludes production from the Hugoton and the California assets for all periods disclosed. Our Q4 2014 worldwide realized oil price of $71.58 per barrel fell by 22 point $6.8 or 24% compared to the 3rd quarter realizations of $94.26 per barrel. In the Q4 of 2014, after tax core income for our domestic oil and gas operations was $59,000,000 compared with $310,000,000 in the Q3 of 2014 $391,000,000 in the Q4 of 2013. On both a sequential quarter over quarter and year over year basis, results at our domestic operations were mainly impacted by lower realized oil prices and to a lesser degree lower NGL prices. Higher oil production had a meaningful positive impact to both earnings and cash flow in the Q4 of 2014 compared to both periods. In the Q4 of 2014, we experienced a narrowing of the differentials in the Permian Basin from what we realized in the Q3 of last year. Total domestic oil and gas production averaged 321,000 BOE per day during the Q4 of 2014, up 6,000 BOE per day sequentially and 26,000 BOE on a year over year basis. Domestic oil production was 189,000 barrels per day during the Q4, an increase of 19,000 barrels per day from the year ago period with our Permian Resources business growing its oil production by 42 percent to 51,000 barrels per day. On a sequential quarter over quarter basis, total domestic oil production growth was 7,000 barrels per day. International after tax core income was $355,000,000 for the Q4 of 2014, a decline of 43% from the Q3 of last year and 50% lower on a year over year basis. The decline for both periods was driven mainly by lower realized oil prices with the sequential quarter over quarter period favorably impacted by higher liftings in both Iraq and Colombia. International oil and gas sales volumes rose by 39,000 BOE per day on a sequential quarter over quarter basis. The improvement was largely due to higher volumes in Iraq resulting from liftings that slipped from prior periods as well as higher spending levels, higher production volumes in Colombia along with increased volumes in the Middle East resulting from lower prices affecting our production sharing contracts. Oil and Gas cash operating costs were 13.50 The increase in cost reflects increased activity in downhole maintenance and higher costs for purchased injectants. The DD and A rate for full year 2014 was $17 per barrel. Taxes other than on income, which are directly related to product prices, were $2.45 per barrel for the 12 months of 2014 compared to $2.48 for the same period of 2013. 4th quarter exploration expense was $59,000,000 Chemical 4th quarter 2014 pretax core earnings were $160,000,000 compared with 3rd quarter results of $140,000,000 $128,000,000 in the year ago quarter. The sequential improvement primarily reflected lower ethylene and energy costs, partially offset by lower vinyls pricing and a reduction of volumes across most product lines due to a combination of maintenance outages, holiday shutdowns and customer initiatives to reduce year end inventories. Midstream pretax core earnings were $168,000,000 for the Q4 of 2014 compared to $155,000,000 in the 3rd quarter and $106,000,000 in the same period a year ago. Fibro's domestic trading book was closed in the Q4 of 2014 and we expect to wind down the remainder of the business in the current quarter. As such, Fibro's results have been eliminated from all core income periods. In the 12 2014, we generated $9,400,000,000 of cash from continuing operations, a decline of approximately $1,000,000,000 compared to the year ago period. Capital expenditures for 2014 were $8,700,000,000 net of partner contributions. Last year's capital outlays included $1,100,000,000 associated with the Alhosin gas project including $470,000,000 related to the rail and sulfur handling facilities $285,000,000 for the BridgeTex pipeline. We received proceeds of $4,200,000,000 from the sale of assets, which included 4th quarter proceeds of $1,100,000,000 from the sale of our investment in BridgeTex, dollars 1,700,000,000 from the sale of a portion of our investment in Plains All American Pipeline GP as well as $1,300,000,000 from the sale of our Hugoton assets in the Q1 of last year. We spent about $1,700,000,000 on bolt on property acquisitions of which $1,300,000,000 was spent in the Q4 on a single acquisition in the Permian totaling 100,000 net acres and including a modest amount of oil production. In October, we received cash proceeds of $4,950,000,000 from the bond offering completed by California Resources. IRS rules mandate that the use of these proceeds be restricted to share repurchase, dividend payments or debt retirement. We paid the 4th quarter dividend and repurchased our shares in December using the restricted cash resulting in a $4,000,000,000 balance at December 31. We received an additional $1,150,000,000 of cash from California Resources concurrent with the spin off in late November. The use of those proceeds is unrestricted. We returned $4,700,000,000 dollars of cash to our shareholders by paying $2,200,000,000 in dividends and repurchasing $25,800,000 of our shares for $3,500,000,000 Last year's share repurchase activity has the benefit of reducing our current dividend outlays by approximately $75,000,000 Our cash balance including restricted cash was $7,800,000,000 at December 31. Our debt to capitalization ratio was 16% at year end. After excluding the impact of non core adjustments and discontinued California operations, our 2014 return on equity was 9% and return on capital employed was 8%. The worldwide effective tax rate on our core income was 39% for the Q4 of 2014 and 41% for the total year. Focusing on 2015, our capital program this year is expected to be about $5,800,000,000 a decrease of 33 percent from our 2014 spending level of $8,700,000,000 Willie Chang will discuss the specifics of the 2015 capital program in a moment. Using a $55 WTI $60 Brent price curve, we expect total company production to be between 630,000,650,000 BOE per day in 2015 or an increase of roughly 6% to 10%. Domestically, we expect our oil production for the total year to grow in the 6% range with the increase coming from the Permian Resources business. We expect gas volumes to decline modestly as we cease development activities in our gas properties. In the Q1, we expect to lose approximately 4,000 BOE per day production in our Permian Basin operations due to weather related shutdowns and freezing conditions that occurred during January. Domestic gas production is expected to decline from 4th quarter levels resulting in a slight sequential production decline on a BOE basis. We expect our international volumes to increase in the Q1 with the Alhosin gas project having started up earlier this month. Volumes from Alhosin should average roughly 20,000 BOE per day in the Q1 as the facilities ramp up through the first half of the year. Full year 2015 volumes from Al Hosn should average about 50,000 BOE per day with more than 40% of the production coming from NGLs and condensate. Production volumes should also be positively impacted from our production sharing contracts that are sensitive to the decline in oil prices. Oil and Gas DD and A expense is expected to be approximately $15 per BOA this year. Combined depreciation for the Midstream and Chemical segments should be approximately $675,000,000 Price changes at current global prices affect our quarterly earnings before income taxes by $32,000,000 for a $1 per barrel change in oil prices and $7,000,000 for a $1 per barrel change in NGL prices. A swing in a $0.50 per 1,000,000 BTUs in domestic gas prices affects quarterly pretax earnings by about $15,000,000 These price changes price change sensitivities include the impact of production sharing contract volume changes on income. Our Q1 2015 exploration expense is anticipated to be about $30,000,000 pre tax. We expect our Q1 2015 pre tax chemical earnings to be about $140,000,000 Lower chlorovinal margins are the primary driver for the sequential decrease in earnings. Using current strip prices for oil and gas, we expect our 2015 domestic tax rate to be at 36% and our international tax rates to be about 65%. I'll now turn the call over to Willie Chang, who will provide more detail on our 2015 capital program. Thanks, Chris. Good morning, everyone. As you now know, our 2015 capital program is expected to be $5,800,000,000 a 33 percent reduction from our 20 14 capital program. All business segments will see cuts in capital spending versus the 2014 levels with the exception of chemicals, which is in the peak year of spending for the Ingleside Ethylene Cracker JV project. Despite lower capital program, we expect to deliver the production growth in 2015 as Steve has said. Now let me expand on the 2015 program of which 80% is in the oil and gas segment and 10% each is in the chemicals and midstream segments. Domestic oil and gas capital will be about $2,500,000,000 or 43 percent of our total capital program, a decline of about $1,000,000,000 from 20 14 levels. Overall spending levels in the Permian will decline slightly and significant reductions will come from Williston and South Texas, which are most impacted by the sharp declines in product prices. Vicki Hollub will provide more details on that later in the call. International Development Capital will be about $2,000,000,000 or 30 3 percent of our total capital program. Spending levels in the Middle East, North Africa MENA region will decline by approximately 1 $400,000,000 mostly from the alhos and gas project completion, Qatar and other mature projects. Exploration capital is expected decrease significantly from the 2014 levels to roughly $150,000,000 Our 2014 exploration program was successful in supporting the appraisal and delineation of a strong inventory of drilling locations, which is the basis of our development program this year. Chemical segment capital will be about $600,000,000 which includes the Ingleside cracker project that we expect to complete late 2016 and commission in the Q1 of 2017. We expect OxyChem to be free cash flow positive through the construction of this project. U. S. Midstream capital will be about $600,000,000 a decrease of about $150,000,000 from the 2014 levels, driven primarily by the completion of BridgeTex Pipeline. Key projects include the continued development of the Ingleside terminal for both propane and crude export terminalling as well as gas processing infrastructure in support of our key development programs in the Delaware Basin. The 2015 capital program I've described ramps down over this year and where we expect to end the year at a balanced free cash flow run rate, which will cover capital interest and dividend payments at the $60 oil environment. It also allows us to develop profitable production growth and allows us to continue to develop the key strategic projects in our Chemicals and Midstream segments. I'd like to take a few minutes to share with you the status on our reductions of our cost structure. Clearly lower oil price environments require lower cost structures to be competitive. Our 2015 plan assumes a very conservative amount of pricing concessions from our suppliers of roughly $250,000,000 for key services. The market environment remains where it is, we expect to see this increase to $500,000,000 or more, which will give us the flexibility to increase activity. We have been very engaged with our suppliers and service providers to capture immediate reductions in costs ranging from 10% to 40%. In many cases, we have amended existing agreements to tie discounts to oil price. The lower the oil price, the greater the discount needed to meet the market environment. We're in the early stages of this process in a finalized agreement with about half of our key suppliers to date. Most of the cost savings that we've incorporated are capital costs, but we also expect operating cost reductions from the $15 per BOE domestic operating cost level. Beyond what we normally look at pure lifting costs of the business, there are a number of cost categories that comprise the total operating costs. Some of these categories are fairly consistent year to year and include labor, generally operating support and staff, plant expenses, pipeline transportation costs, surface maintenance. This activity allows us to produce our product reliably, safely and responsibly. Now highlighted are a number of categories where we do expect to see significant reductions and are much more discretionary in nature. These include well workovers, well enhancements, downhole maintenance and purchased injecting costs primarily CO2. Clearly in a low product price environment, many of these activities are just not economic to pursue. We also expect to see energy cost reductions which are linked to oil and gas prices, so they too will come down in this price environment. This should give you more perspective on another key area of opportunity that we're working hard on and we'll share more specifics with you as we develop more certainty around market environment and other optimization and efficiency improvements. I'll conclude my remarks by emphasizing that our capital allocation is very dynamic in nature. We will proactively manage our program and we have ample flexibility to respond to both stronger and weaker conditions. I'll turn the call over now to Vicki Hollub, who will review our 2015 domestic oil and gas plants. Thank you, Billy. Today, I'll review the highlights of our Permian Resources activities in the Q4 and then I'll provide more details about the 2015 capital programs in our U. S. Operations. In the Q4, Permian Resources achieved daily production of 84,000 barrels of oil equivalent per day, which is a 9% increase from the 77,000 barrels of oil equivalent per day that were produced in the Q3. With regard to oil, we produced 51,000 barrels of oil per day for the 4th quarter. This is a 42% increase from a year ago and a 19% increase from the previous quarter. During the Q4, our capital expenditures were 791,000,000 dollars We operated 29 rigs and drilled 85 wells, including 56 horizontals. We placed 70 wells on production, including 44 horizontals. At year end, 11 wells were on flowback and 61 were not yet completed. In the Delaware Basin, In our Barilla Draw area, we placed 7 horizontal wells on production in the Wolfcamp A and B benches. These wells achieved an average peak rate of 1500 BOE per day and a 30 day rate of 11.90. We're extremely excited by the results achieved on the Peg State 258 6H, where we optimized the landing point and cluster spacing. This well achieved a peak rate of 2,400 BOE per day and a 30 day rate of 17 60. Additionally, we placed our first 2 7,500 foot lateral wells, the Buzzard State 9H and 10H on production with excellent results. Both are completed in the Wolfcamp A. The Buzzard State number 9H achieved a peak rate of 20 20 BOE per day and a 30 day rate of 17.80. We're achieving excellent initial results on our wells with sand concentrations ranging from 17 to £2,250 per foot. For example, our Chevron Minerals 17.5 well achieved a peak rate of 1800 BOE per day. In New Mexico, we continue to be pleased by the performance of our Bone Spring wells. Recently, our Cedar Canyon 27 State 4H was placed online with an average peak rate of 17.90 and a 30 day rate of 10.30 BOE per day. In the Midland Basin, we operated 10 horizontal drilling rigs and 4 vertical drilling rigs during the Q4. We drilled 38 wells and placed 31 on production. In the Spraberry, Wolfcamp A and Wolfcamp B benches, we placed 17 horizontal wells online with an average peak Spraberry wells online with an average peak rate of 900 BOE per day and a 30 day rate of 8.50. And last quarter, we discussed our South Curtis Ranch 3526H well in the Lower Spraberry. We're excited to report the 6 month average production for this well was 7 40 BOE per day. In one of our new development areas, the Birchen 1411 well achieved a peak rate of 15.60 BOE per day and a 30 day rate of from the Wolfcamp A. The aggressive exploration and appraisal programs we completed in 2014 have helped us to clearly identify our best benches and to achieve significant improvements in well productivity and operational efficiency. We'll continue to improve these results in 2015. Now I'll provide additional details about our 2015 capital plans and our domestic operations. Our most significant capital reduction will come in our Mid Continent business unit, which includes our Williston operations and our gas properties in the Piazza in South Texas. We plan to spend $285,000,000 in 2015 versus $570,000,000 spent in 2014. The 2015 capital program will focus on maintenance activities along with high return workovers. This fits with our strategy to focus capital on higher margin production. In the Permian Basin, we have 2 distinct but synergistic businesses Resources and Enhanced Oil Recovery. The Resources business provides the unconventional portfolio and expertise to achieve accelerated growth supported by our EOR business, which provides the cash flow from efficient high volume production. In Permian Resources, our capital expenditures will be approximately $1,700,000,000 This is a $200,000,000 reduction from 2014 expenditures. We plan to operate an average of 19 rigs and drill approximately 167 horizontal wells, which is equal to the number of horizontal wells we drilled in 2014. Additionally, we'll drill only 48 vertical wells versus the 137 vertical wells drilled in 2014. Wells are drilled to hold acreage or to appraise new benches. Our 2015 capital program will focus on the development of our best benches in concentrated geographic areas. In the Midland Basin, our development activity will be mainly in South Curtis Ranch and Merchant. Here we plan to drill 40 5 Spraberry wells where performance is matching a 750,000 BOE type curve. In the Delaware Basin, we plan to drill 67 Wolfcamp A wells a concentrated number of leases in the Greater Barilla Draw area. Our Wolfcamp A wells in the Delaware are exceeding a 900,000 BOE type curve. In New Mexico, we plan to drill 22 Bone Spring wells. We'll execute this targeted capital program utilizing a manufacturing approach, which will include the efficiencies of pad drilling, batch drilling of the vertical and lateral sections of the well along with zipper fracs. This strategy will enable us to grow our production at a higher rate with less capital than in our 2014 appraisal program. In the Q1 of 2015, we plan to operate an average of 29 rigs. We expect to drill 85 wells and place 108 wells on production, including 63 horizontal wells. We're on pace to have 42 wells on flowback or on production in January. Permian Resources has a sufficient inventory of wells to continue profitable development in a low price environment. Based on our current cost structure, we have the ability to continue drilling profitable wells for several years. We're taking the following actions ensure we can deliver even more locations in this low price environment. First, we'll continue our investment in reservoir characterization and optimization of key variables such as well bore spacing, lateral length, proppant concentration, surfactants, cluster count and spacing. These investments drive resource recovery and are fundamental at any price. 2nd, we'll continue to apply enhanced manufacturing principles to our development program. This will enable us to achieve efficiencies at an accelerated pace. 3rd, we'll continue our efforts to enhance our base management and maintenance activities. This will ensure optimized production levels while minimizing associated operating costs. Lastly, we continue to aggressively work with our suppliers to I've discussed in previous calls. I'm encouraged by the urgency and actions our employees and contractors have already demonstrated in delivering on these initiatives. I'll now discuss our Permian EOR business. While it hasn't drawn much intention in the last couple of years with the industry focused on high growth resource programs, our Permian EOR business remains very profitable. Oxy is the leader in Permian Basin CO2 flooding with over 30 active floods and 40 years of experience. This business has weathered prior downturns with resilience and the low decline of these large properties provides a stable base to our production at an advantage to cost. The Permian EOR business has the agility, scale and cost structure to operate in an ultra low pricing environment. Currently, our total cash cost in Permian EOR is $30 a BOE as shown on the slide. This takes into account the cost reductions that we've already achieved. If prices stabilize at today's level or continue to decline, all costs that are linked to oil prices would also decline, including energy, CO2, production taxes and discretionary well maintenance activities. For example, in a $35 per barrel oil price scenario, our total cost would reduce to approximately $22 a BOE. Our DD and A cost is approximately $10 a BOE. We continue to see opportunity for investment in CO2 projects in the current oil price environment. Last year, we drilled 277 infill wells and continued construction of facilities for new CO2 projects. When completed, our new project at South Hobbs will develop 28,000,000 barrels of oil equivalent of reserves at a cost of $10.60 per BOE. The CO2 floods have remained a strong business through technology advancement that improves recovery from our large portfolio of conventional reservoirs. In the Permian, Oxy operates reservoirs that collectively contained approximately 18,000,000,000 barrels of original oil in place. Hence, even small improvements in recovery efficiency can add significant reserves. An example of this has been trend towards vertical expansion of the CO2 flooded interval into residual oil zones or RAS targets. Over the last few years, we've had an ongoing program of deepening wells with 109 wells deepened in 2014 and 81 wells planned in 2015. This activity escapes much attention because we utilize work over rigs to drill the extra depth into additional CO2 floodable sections of the reservoir. These low cost projects add reserves at development rates ranging from $3 to $7 per BOE. These opportunities exist under many of our CO2 projects and thus far only a fraction of the CO2 flood wells have been deepened. In Permian EOR at 2015 capital The Permian EOR at 2015 capital expenditures will be approximately $500,000,000 to continue expansion of CO2 floods and water floods. The EOR business is expected to generate free cash flow this year even in the current oil price environment. We will complete construction and begin injection at the new South Hobbs project. Additionally, we will also start construction of a significant expansion at the successful North Hobbs CO2 flood, where CO2 flooding has Our EOR business has Our EOR business has unrisked gross resource potential of up to 1,900,000,000 barrels, providing us with a vast inventory of future CO2 projects, which could be developed over the next 20 years or accelerated depending on market conditions. Our current strategy for this business is to invest sufficient capital to maintain current production, thereby providing cash flow to support growth in our Permian Resources business. By exploiting natural synergies between our EOR and Resources businesses, Oxy is able to deliver unique advantages, efficiencies and expertise across our 2014 exploration and appraisal programs have successfully set us up for a strong 2015 development program in Permian Resources. Our portfolio of high quality assets combined with our value oriented discipline enables us to deliver efficient growth. We'll execute a focused development strategy in 2015 and continue to pursue step changes in well productivity and cost structure. Our Q1 production of 2015 will be negatively impacted by approximately 4,000 BOE per day due to the winter weather events that occurred in the Permian Basin in January, but we do expect to deliver our previously stated target of 100,000 BOE per day from Permian Resources in 2015. Our combined EOR and resources production is significant and accounts for 15% of the production from the Permian Basin. Our development program along with the synergies delivered by our resources EOR and midstream businesses have us well positioned to meet the challenges of this lower price environment. Now I'll turn the call back to Chris. Thank you, Vicki. Now we'll open the call up for questions. Thank you. We will now begin the question Our first question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead. Thanks. Good morning, everybody. I wonder if I could take 2 please. Vicki, this one is probably for you. I guess just to be absolutely clear, in this current oil price environment, not the $55 that you've put in the plan, I guess, but is the Permian program delivering positive returns? And if you could maybe give some color as to what royalty ownership or what royalty rates you might have in the program for the current year, I guess, in the Delaware Basin? Yes, Doug. Currently, our program at today's prices will deliver about 15% to 20% rates of return. And the reason for that is we had an aggressive program appraisal program in 2014. So we have we are targeting in 2015 our best benches and our best areas. And We've had really good success recently with improving our completion designs. So we expect the returns to be in the 15% to 20% range. And if you'll refer back to the chart I included in the presentation in Q3, you'll see that if you look at the areas where we're developing, I think I have some numbers there that generally would enable you to get to the net interest. Okay. And maybe just not to labor the point, thank you. But what kind of inventory in terms of at the current pace, the wells that we've achieved or the programs that achieve that can return to $45 oil. Is that like high grading the portfolio? Or is that a multi year inventory that you believe to achieve that? Yes. We have high graded the portfolio, but we expect to be able to at this pace go at least 3 to 5 years with the inventory that we have. And if prices continue to improve with respect to the cost structure, we and I'm not I don't mean prices, oil prices. I mean, if our cost structure continues to improve based on prices, we expect that inventory to increase. So we expect over time to be able to increase the inventory that we have today. But at today's pace, it would be about 3 to 5 years. Okay. Thank you. My follow-up is, I guess, I know there's going to be a lot of other questions on new operations. But Steve, I wonder if I could go back just to the progress on the asset sales in the Middle East. Any updates you can provide especially now that Al Hosn is on stream? And given that the Omani contract expires this year. Could you help us with how you see maybe things changing in this oil price environment if at all? Well, of course, the countries are saying that the prices will quickly rebound once the evil shale producers stop producing. So I but I think until that happens, I think that it's going to be slow. I mean, obviously, the countries are affected by this. I mean, they're actually affected more by the decline in oil prices than anybody really. So I expect it to be slow. I think Oman will move along all year. We just don't know what's going on in Abu Dhabi at this point. Okay. I'll leave it there. Thanks everybody. Thanks. Our next question is from Paul Samky of Wolfe Research. Please go ahead. Hi. Good morning, everyone. Steve, talking again back to the CapEx program, it seems that you've used the strip to come up with the 2015 number. I just wondered how much lower would you have to take CapEx if we stay at this more like $45 environment for let's say another year? Thanks. Well, for another year, it gets a little more complicated. The capital spending on the chemicals and the midstream stuff will fall off naturally going into next year. So the capital would come down anyway. We've only built in the cost savings that sort of been achieved at this point. And there's at least another $250,000,000 and maybe another $500,000,000 in savings if just from the suppliers if prices needed to be low because we basically for a lot of them we've indexed the how much we're paying to the oil price. So I don't really know exactly what it would be, But I would guess that if you use if it's $60,000,000 recovering everything at the end of the year, there's some other stuff that would be reduced and it's probably a little lower than $60,000,000 actually. And so if you said, okay, it's going to be $10 less, dollars 10 less is $1,000,000,000 So we'd have to reduce the capital by $1,000,000,000 Most of that we get from suppliers, but there would be some things that would have to be cut. Thank you. That's helpful. And then my follow-up would be, have you considered selling Oxy? And have you considered any major acquisitions? Thank you. Right now people are cash flow challenged, so I expect selling Oxy is probably not real likely. But I looked at Chevron, it looks like they don't have any free cash. So anyway, if you look at we haven't signaled any major acquisitions. It's way too early to be talking about acquisitions. I think there's still a lot of whistling in the graveyard going on and way too early to consider any kind of acquisitions. Again, we generally are not interested in public acquisitions. Got it. Thanks. Helpful, Steve. Thank you. Our next question is from Doug Terreson of Evercore ISI. Please go ahead. Good morning, everybody. It's a nice new name. How about that? I had a question about divestitures as well. There's a commentary in the market about possible divestiture of the L Hosen project that you guys have just completed. And so just wanted to ask, is that a possibility? Just if you could provide some color on that? And again it wasn't your commentary it was that from others. But could you just give us an update on the strategic track of that position? Well, let's talk about what it is. Okay. We've already spent the money. Yes. Yes. So there's not really much capital going forward. There might be an expansion, which is where probably cheap capital out a year or so. But putting that aside, so in a crappy oil price environment probably generate about $300,000,000 of free cash and sort of a decent one about $600,000,000 of free cash a year. So if you multiply it out by the 25 years that remain roughly, you multiply through so you get somewhere between $7,500,000,000 and whatever it is $12,500,000,000 of cash generated over the 25 year period. So from our perspective, for a company that pays a lot of dividends and that sort of thing, having that sort of asset makes good sense to us. If on the other hand, for a variety of reasons, somebody wanted to buy 20%, 30% of it to free up cash for something that maybe works better. I guess we're open to that. But only in a if you just look at it intrinsically for somebody who pays a lot of dividends, I think it's a pretty good asset over time. Okay. No, it seems like it. And then also there's a lot of commentary about Moxie's historical proficiency and enhanced oil recovery. And so I wanted to see how you're thinking about the opportunity in Mexico or potential opportunity, meaning do you consider this to be kind of an area of natural alignment for OXY? And if you do, how do you think about the opportunity in Mexico? Well, I mean there's 2 issues like always in foreign activities. 1 is the quality of the asset being offered. And I think if intrinsically they have some decent enhanced oil recovery assets on offer. The other part of it is what's the financial arrangements. I mean if you look at some of the other places, I won't say where, but look at some of the other places where intrinsically the asset might work at $20 a barrel or something like that. But if you lay the contract over, it doesn't really work at today's prices. And I think that's the issue in Mexico. While the asset may be attractive and you can get a lot of 100 if you had 100% of it, it would be something that would work pretty well. But they've taken a pretty aggressive view about contract terms. I think they took the Chinese menu approach where they pick one from every column in everybody's contract. So I think they got a pretty difficult contract to want to do it. And we're not doing it for advertising expense. I think we'd rather frankly put the money into the CO2 projects in the United States where we have low royalties, in fact, in some cases we own the royalties than to fool around with some ridiculous contract in hopes it gets better over time. Okay. Thanks a lot, Steve. Thanks. Our next question is from Leo Mariani of RBC. Please go ahead. Hey, guys. Obviously, a lot of focus here in terms of how you guys can kind of conservatively manage things. I wanted to kind of flip the question around and just get a sense if we do start to see an oil price recovery in the second half of the year in 2016, kind of how quickly you can bring rigs back in the Permian? And then just additionally, is there any kind of loose price framework we should think about where if we do get to 70% is that the number where you start adding rigs? Anything could help in terms of price would be great. Yes. I think the answer to your question is there's a lot of rigs around in the Permian and there's more available every day. So I don't think bringing rigs back is going to be a problem. I think the program has to be somewhat disciplined. And so we'll be cautious in adding rigs because while the prices may rebound, it may go back down again. I mean, I'm more concerned really about the demand issues in the world than I am how much the U. S. Business is producing. But I think if you look at it and said, clearly if you hit the $60 the program will be the way we've described it. As you get to $70 and maybe a little more aggressive and as you get north of $70 I think we'd be somewhat more aggressive. But I really think that if you look at the if you were able to see the layers inside the company, we've got it all matrix and we can actually figure what makes sense at whatever price you want. And so our program going forward would reflect that expectation. But right now our expectation is conservative I would guess. All right. Maybe could you just talk a little bit about the importance of returns on the drilling program plus kind of versus desire to kind of stay cash flow positive or cash flow neutral when you include dividends, obviously, focused on getting back to this cash flow neutrality exiting the year at 60. So as we think about a recovery case in 2016, how much are you focused on making sure you don't outspend versus hey if the returns are good at 70 we're willing to outspend? Can you just talk to that? You got to be pretty certain about your returns before you outspend. No offense to any oil engineers, but they tend to be a little more optimistic than the actual outcome. And so the corporate management will be fairly conservative about things. So we need some margin of error. There's a lot of damage being done in the business. I think people everybody's balance everybody's balance sheet is going to be not quite as good as when they started. I mean we're starting in a good spot, but I think even the large companies will have more debt laden balance sheets and not really much to show for it. So I think you just got to be pretty careful in this environment about what you're doing. No one really even though the price may recover in the back half of the year, I'm still concerned about world demand for oil although I am heartened to see that in the United States at least the lower gasoline prices have created more people riding around in big cars. So we're doing that in our house. We're riding around the corner. No. That makes sense for sure. And I guess just lastly in terms of M and A, I just wanted to kind of clarify some of the comments. You certainly talked about sort of a challenging market for acquisitions at this point in time. It sounds like the bid ask spreads haven't reset. But I also hear in the prepared comments that you had made an acquisition in the Q4 of 2014 for 100,000 acres in the Permian for around $1,300,000,000 Can you give us some more color on what you picked up there and what you think about it? Yes. It was early in the quarter. We're probably a little early in the acquisition I think acquisition cycle. We got we think a price that works in this environment. It's good acreage and we got picked up a modest amount of production. So the goal of the acquisition program in the Permian is to add to our current position, so we can drill more efficiently. I mean, it's not really to get more acres, you got plenty of acres. I mean, the question really is can we fill in our play what we currently own and allow us to drill more efficiently without moving the rig so much. So this sort of acquisition was designed with that intention that we could that would allow us to be more efficient. Without efficiency gains, I think acquisitions are not very interesting. Okay. Thanks a lot. Our next question is from Jeffrey Campbell of Tuohy Brothers Research. Please go ahead. Good morning. First, just a couple of quick Vicki questions. I noticed that the Delaware Basin Second Bone Spring had been rerated from appraisal to development from last quarter for this one. Is that the zone that you're focusing on in New Mexico? Yes, it is. We're only going to drill Second Bone Spring wells in New Mexico in 2015. Okay, great. It sounded like the reduced vertical drilling is tied to less appraisal work. Can you identify which appraisal zones are likely to be most affected by the reduced 2015 CapEx? It would really be the zones, the benches that are away from our current development areas. So for example, we've appraised the benches at South Curtis Ranch and several in the Brilla Draw area. So what we're really going to try to do now is focus on the development in those areas. And our appraisal program was so far ahead. We still know a lot about some of our other areas. We just wanted to get into manufacturing mode so that we could improve our cost efficiency. So we're still we're pretty much way ahead with our appraisal program right now. The thing that we want to do next is to continue to improve on our completion efficiency. Okay. Thank you. And Steve, this is the last question. You've spoken some of our concerns on demand. Can you outline where you look for signs of improvement, particularly as we all can expect that U. S. Oil production is going to increase as oil prices begin some kind of recovery? Well, I think if I look at U. S. Oil production, it will probably increase in the 1st and second quarter and maybe the rate of increase in the 3rd quarter will fall off and maybe there'll be some decline in the 4th. The main consumer of oil today is China. Any recovery in Europe would be helpful, but it's not a driver. And so it's China and maybe India. Also the Middle East has been a large consumer of oil recently. And the current environment is it's just hard to say whether that will continue whether that growth will continue or not. I think the world economy I think there's I think that's the big question mark going forward. If we get demand growth, lower oil prices stimulate demand, this current situation will be over fairly quickly. If we don't this could drag on quite a while. Okay. Thanks very much. Our next question is from Jason Gammel of Jefferies. Please go ahead. Thanks. I wanted to ask a question about the importance of operational momentum in the Permian Basin. And really where I'm coming from here is you're generating very acceptable returns at current prices, but that could potentially be significantly higher rates of return assuming a recovery in the oil price. So given that you're more what stops you from let's say having the rig count in the first half of the year, what stops you from let's say having the rig count in the first half of the year and then moving up to a much higher count at the back half of the year? It's basically the contractual position we have. We've contracted for some rigs that basically come off at midyear. And by the time you drill, I mean, just think about the timing. Let's say you actually drill a well in the first quarter, it's the Q3 before it actually produce you actually get the revenue. So the stuff in the Q1 will basically be a 3rd and 4th quarter production for us. But I think we have some contracts that need to roll off and that's really controlling the timing more than anything right now. Okay. So there's nothing related to utilization of workforce and efficiencies that could be lost if you did have a sudden shutdown or anything of it? Well, I mean, it's always inefficient. If you just all of a sudden stop in the middle, it's always going to be a problem. So it's got to be a phasedown. But it's contractual and the notion that maybe there'll be some recovery in the back half of the year and you need to drill wells sort of in this first and second quarter to have production in the back half of the year. We're pretty cautious about the whole thing. But you just can't sense things to 0 just an impractical thing to do right now. We're doing the best we can to manage through it. And I think we'll be all right. Okay. And if I could ask one more on a completely unrelated topic. You mentioned that the restricted cash was used to pay the dividend in the 4Q. Should we think about in a low price environment restricted cash essentially funding the dividend? And how does that affect then the pace of share repurchases? I know you said that the $71,000,000 you still ultimately expect to buy in on the share repurchase program, but could that be a 5 year period or you be thinking more like a 2 year period? We'll start with I wouldn't get wrapped around the axle on this restricted cash stuff. Cash is reasonably fungible and all we're doing is showing you the account paying down. It's not really so we rather than keep more restricted, we just say it comes the dividend comes out of that bank account. So it's got to come from somewhere. We don't really know about the pace. We are price sensitive. I'd point out that really the domestic program last year had an F and D if you just cut through all the BS of $13 $14 and we expect to bring that down some more. So we're running a pretty profitable program maybe not a $25 oil, but certainly in the 50s. So I'm as far as the pace of the share repurchase, the stocks are volatile. And when there's negative volatility, I guess volatility is up always used negatively, but nobody ever talks about upside volatility. But downside volatility, which I'm sure will come at some point in this, that's when we'll step up and buy a lot of shares rather than just sort of treat it as a constant flow. So I don't really know. We set aside a fair amount of money for that this year, but if prices are more attractive, we'll spend more. I shouldn't I don't really have a budget in the usual sense of the word. And would you want to comment on what you would find an attractive price to? No, I wouldn't like that. Okay. I figured that. Thanks very much. Our next question is from Brian Singer of Goldman Sachs. Please go ahead. Thank you. Good morning. I wanted to follow-up on a couple of earlier questions. First, you mentioned that you would have flexibility to increase activity if you can get another $250,000,000 in savings. Can you just talk more to what that scenario looks like? Would that mean your portfolio would achieve attractive returns at $60 Brent and you'd ramp back up in the areas that you're currently ramping down I. E. You'd recommit to the Mid Con or would you just ultimately look to focus more on the Permian incrementally when prices It would be all Permian. The Mid Con is well, putting aside North Dakota is basically gas. So the Brent price is sort of irrelevant. And it really can't compete for dollars for quite a while in against the Permian. North Dakota has this huge differential to price right now. And so that's really what's discouraging us up there. So I think you should plan that in a $60 environment or $65 environment or whatever you're thinking that we would spend more in the Permian. The savings $250,000,000 we could add about 3 rigs on an annual basis to cover that. So to give you it was running about $100,000,000 a year or so it's probably running a little less now. So I mean that's the way to think about how much more we would do. But we've got a fair inventory. And as prices move up, the inventory obviously expands. Great. Thanks. And then back to the Permian acquisition and looking at that 100,000 acre deal you mentioned the strength was the efficiency that it has with existing positions. Based on the placement of your existing acreage within the Permian, can you just talk to the scope for how many more fill in acres would be optimal for you with your acreage positions and whether you see those opportunities becoming available? We don't know about opportunities because some people may have debt and they probably don't want to sell before less than their debt. We just don't have any way in pacing that at this point. We don't really know. Know. If we found more in the Barilla Draw area that would be real interesting and there is acreage around there that's held by others. And some a little bit in the Midland Basin that fits with what we have. I don't know whether it's 300,000 acres or 200,000. It's not millions of acres. Great. Thank you for the color. Thanks. Our next question is from Ryan Todd of Deutsche Bank. Please go ahead. Great. Thanks. Good morning. Maybe a couple more follow-up questions on the Permian. Can you talk a little bit about what you're seeing from well performance point of view in 2015, 2016 production targets seem largely unchanged despite CapEx cuts? Is this efficiency gains, better well performance, combination of both? It is. We haven't changed our 2016 target yet, because we're still anticipating that if prices were to go up, we'd have the flexibility to add rigs. We may have to adjust that a little bit toward the end of this year if prices remain where they are. But one of the things that we're encouraged with is we certainly are seeing better performance, particularly in the Barilla Draw area and particularly with the last well that I mentioned in the call today. We're seeing not only opportunities to improve our landing points within the benches, but our completion efficiencies are improving. And so we're really encouraged with what we're seeing there and with what we're seeing in from the Spraberry in the middle of the basin. Okay. Thanks. And then maybe on cost at this point, the 2015 budget your per well budget cost in the Permian in 2015, what is it relative to 2014 cost? And is that mostly efficiency gains? Or do you have anything priced in for price deflation? Or is that additional upside? Yes. We priced about $250,000,000 in the for cost reductions that we pretty much achieved. And we expect to get some more, but we certainly priced that in already. And efficiency gains are built in. Efficiency gains really come from focusing on a few places rather than going all over creation. I mean that's really what causes and we built that in. Okay. So additional I guess the additional $250,000,000 that had highlighted in the slide, there's certainly potential downside from a price depletion point of view, but efficiency gains are at least mark to market from where you guys are right now, I guess? I guess that's right. Okay. Thanks. I'll leave it there. Our next question is from Evan Kallio of Morgan Stanley. Please go ahead. Hi. Good morning guys. A few quick follow ups for me. First on the buyback, I presume most of the buyback in 4Q was executed after or in December after the spin. Great. And second, I know that you're price sensitive and or I would say price aware. I mean, so do you see the flexibility to use your currency for adding assets if your view was that it were to be expensive relative? Well, it's and we've never I think I used stock once in the last 20 years and I regretted it ever since. So maybe I've been doing this too long. So too good a memory of bad outcomes. If you're going to use your stock, you really have to make sure that whatever you're doing is significantly accretive. Cash at least cash, you're only paying 3% or whatever it is interest. But if you're using stock, we're paying almost 4% in dividends. But putting even putting that aside, we don't want to dilute the quality of your portfolio with some wacky deal. And so if you're going to gamble on wackiness, you probably ought to gamble with cash rather than stock. All right. So maybe a follow-up on the Permian acquisition that you made in the quarter. I mean any color in terms of location, well inventory? It's a Midland Basin acquisition and there's a lot what just a matter of price. I mean, when you talk about locations, you also got to factor in price. I think going in, I thought that I think it was 2,700 about 2,700 locations. Okay. And will you expect activity there in 2015? Or will that be part of your focus area? No. Okay. Yes, we do. Is that due to economics or because it's non HBP? It's economics principally. There's some non HPP when they're we'll use probably use a vertical rig there to keep some of the acreage. Great. Thanks for taking my questions. Thank you. Our last question is from Matt Portillo of GBH. Please go ahead. Good morning all. Good morning. Just a quick follow-up question in regards to your Permian rig count and spending program. I believe you mentioned you're running roughly 29 rigs coming into the Q1. I was curious if you could give us a little bit of color on the cadence of kind of that rig drop as you move through the year to average the 19 rigs in 2015? And then I have a follow-up question in regards to your overall capital program. Yes. But currently, we're going to average also 29 rigs in Q1. And then we as towards the end of Q1, we start to ramp down. And by Q3, the beginning of Q3, we'll be at 15 rigs and at 15 through the rest of the year. Thank you. And then in regards to your corporate capital program, you mentioned the Q1 will be a bit heavier in terms of CapEx versus the back You can see that in the rig count. I mean it just flows out of that rig count. Right. And I guess just to maybe try to get a little bit of color around how we should think about the magnitude of the change on CapEx. Is there any color you could provide as we think about kind of the exit capital program you've talked about in the Q4 of 2015? How we should kind of think about the magnitude of the change over the year? Willy can answer that. I would say directionally, it's we're starting off at about 1,800,000,000 dollars 1,000,000,000 of Q1 and ramping down about $1,200,000,000 rough numbers. Perfect. That's very helpful. Thank you very much. This concludes our question and answer session. I'd like to turn the conference back over to Chris Degner for any closing remarks. Thank you, Emily, and thanks everyone for participating today. Bye. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.