Good morning, and welcome to the Occidental Petroleum Corporation third quarter earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your telephone keypad. Please note this event is being recorded. I would now like to turn the conference over to Chris Degner, Senior Director of Investor Relations. Please go ahead.
Thank you, Denise. Good morning, everyone, and thank you for participating in Occidental Petroleum's third quarter 2014 conference call. On the call with us this morning 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 Cheng, 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 CFO, Chris Stavros, who will review our financial and operating results for the third quarter and also provide some guidance for the current quarter. Our CEO, Steve Chazen, will then provide an update on the progress of our strategic initiatives and an outlook for 2015. Vicki Hollub will then provide an update of our activities in the Permian Basin.
Willie Cheng will conclude the call with an update on Oxy's midstream operation. 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-K. Our third quarter 2014 earnings press release, the investor relations supplemental schedules, 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 Chris Stavros. Chris, please go ahead.
Thanks, Chris, and good morning, everyone. We generated core income of $1.2 billion for the third quarter of 2014, resulting in diluted earnings per share of $1.58, a decrease from both the year-over-year quarter and the second quarter of 2014. The decline in core earnings was attributable mainly to lower realized oil prices on our worldwide production and the sharp decline in trading performance on a sequential quarterly basis. For the fifth consecutive quarter, we continued our strong domestic oil production growth. We met our guidance and achieved a year-over-year domestic oil production increase of 20,000 BOE per day, or about 8%, led by our Permian and California assets. We also repurchased 4.7 million shares of our stock during the third quarter and ended the period with $2.9 billion of cash on our balance sheet.
Oil and gas core after-tax earnings for the third quarter of 2014 were $1.1 billion, $90 million lower than the second quarter of this year and $236 million lower than last year's third quarter. For the third quarter of 2014, total company oil and gas production volumes averaged 755,000 BOE per day, an increase of 19,000 BOE in daily production from the second quarter and 6,000 BOE per day from the same period a year ago, which excludes production from the Hugoton assets for all periods. Our third quarter 2014 realized oil prices of $94.68 per barrel fell by $5.70 compared to the second quarter realizations of $100.38 a barrel. In the third quarter of 2014, after-tax core income for our domestic oil and gas operations was $538 million. On a sequential quarter-over-quarter basis, results at our domestic operations were negatively impacted by lower realized prices across all products.
Improved volumes, however, offset roughly a quarter of the earnings decline caused by lower prices. On a year-over-year basis, domestic operations declined by $252 million after tax, which reflected the impact of lower realized oil prices, partially offset by increased oil production volumes. The lower realized oil prices were impacted by the large differentials we saw in the Permian Basin. Willie Chiang will provide a more in-depth discussion around Permian differentials later on in the call. Total domestic oil and gas production averaged 475,000 BOE per day during the third quarter of 2014, up 11,000 BOE per day sequentially. Domestic oil production was 282,000 barrels per day during the third quarter, a new quarterly record for Oxy. Domestic oil production volumes increased by 20,000 barrels per day from the year-ago quarter, with our Permian Resources business growing its oil production by 26% to 43,000 barrels per day.
On a sequential quarter-over-quarter basis, total domestic oil production growth was 6,000 barrels per day. International after-tax core income was $624 million for the third quarter of 2014, with results improving by 8% sequentially due to a lifting in Iraq, which had none in the second quarter, and higher sales volumes in both Colombia and Qatar. Income for our international oil and gas operations remained about flat versus the year-ago period. International oil and gas sales volumes rose by 4,000 BOE per day on a sequential quarter-over-quarter basis. The improvement was largely due to higher volumes in Colombia, which experienced fewer pipeline incidents in the period. Oil and gas cash operating costs were $14.89 per barrel in the third quarter of 2014, compared to $14.68 per barrel in the second quarter.
Taxes other than on income, which are directly related to product prices, were $2.64 per barrel for the third quarter of 2014 and $2.80 for the first nine months of the year. Third quarter exploration expense was $53 million. Chemical third quarter 2014 pre-tax earnings were $140 million, compared with second quarter results of $133 million and $181 million in the year-ago quarter. Although slightly below our guidance, the sequential improvement in the third quarter was due to higher caustic soda prices and volumes, along with lower natural gas costs, offset by lower vinyls margins resulting from rapidly escalating ethylene costs. We expect our fourth quarter pre-tax chemical earnings to be about $115 million, reflecting a historical seasonal slowdown due to the combination of maintenance outages, holiday shutdowns, and some customer initiatives to reduce year-end inventories.
Midstream pre-tax segment earnings were $125 million for the third quarter of 2014, compared to $219 million in the second quarter and $212 million in the same period a year ago. The 2014 sequential quarterly decline in earnings resulted mainly from much weaker trading performance, driven by sharp commodity price movements during the period, partially offset by higher income from power generation and the domestic pipeline businesses. In the first nine months of 2014, we generated $8.6 billion of cash flow from operations before changes in working capital. Working capital changes decreased our cash flow from operations by $416 million to $8.2 billion. 2014 year-to-date cash flow from operations declined by approximately $1.6 billion compared to the same year ago period.
The first nine months of 2014 included tax payments of $570 million related to the gain of the sale of the PAGP units and our Hugoton assets, and the first nine months of 2013 included the collection of a tax receivable. Capital expenditures for the first nine months of 2014 were $7.3 billion, net of partner contributions. Our capital outlays included $410 million associated with the Al Hosn Gas project and $275 million for the BridgeTex Pipeline. During the first nine months of this year, we received proceeds of $1.3 billion from the sale of our Hugoton assets and spent about $425 million toward domestic bolt-on acquisitions. We issued $1.6 billion of commercial paper during the latter part of the third quarter as part of our short-term cash management process, which has already been repaid.
After paying dividends of $1.6 billion, buying back $2.1 billion of company stock, and other net flows, our cash balance was $2.9 billion at September 30. Our debt to capitalization ratio was 16% at quarter end. Our 2014 annualized return on equity was 12%, and return on capital employed was around 10.5%. Earlier this month, we received cash proceeds of approximately $5 billion from the bond offering completed by California Resources. IRS rules mandate that the use of these proceeds be restricted to share repurchases, dividend payments, or debt retirement. We will be receiving an additional $1.2 billion of cash from California Resources concurrent with the spinoff in late November. The use of these proceeds will be unrestricted.
The worldwide effective tax rate on our core income was 40% for the third quarter of 2014, and we expect our combined worldwide tax rate in the fourth quarter to remain about the same. Lastly, I'll outline some guidance and a few points on our reporting disclosures for the fourth quarter. Due to the recent sharp decline in oil prices and the completion of the California spinoff at the end of next month, it will be difficult for the financial community to predict our earnings per share for the fourth quarter. When Oxy completes the spinoff of California Resources at the end of November, we will reclassify their financial and operational results to discontinued operations for our core results disclosure. As such, our fourth quarter core income will exclude all of California results and income on a reported basis will include two months of California results.
Total year results on a reported basis will include 11 months contribution from our California operations classified as discontinued. Included in the IR supplemental schedules is a pro forma table segregating Oxy's sold and spun off domestic production from our ongoing operations for the historical quarterly 2013 and 2014 periods. For the fourth quarter, we expect to see continued production growth from the Permian Resources. In addition, with the startup of the BridgeTex Pipeline, Oxy will capture a portion of the spread between LLS and WTI Midland on approximately 200,000 barrels per day of oil transported to the Gulf Coast. Willie will discuss the benefits of the BridgeTex startup in a few moments.
We expect our international volumes to increase in the fourth quarter with the Al Hosn Gas project coming online and the positive impact to volumes for our Production Sharing Contracts that are sensitive to the decline in oil prices. On a go-forward basis, excluding California, price changes at current global prices affect our quarterly earnings before income taxes by $29 million for $1 per barrel change in oil prices and $6 million for $1 per barrel change in NGL prices. A swing of $0.50 per MMBTU in domestic natural gas prices affects quarterly pre-tax earnings by about $15 million. These price change sensitivities include the impact of Production Sharing Contract volume changes on income. Our fourth quarter 2014 exploration expense is anticipated to be about $60 million pre-tax.
I'll now turn the call over to Stephen Chazen, who will provide an update on some of our strategic and growth initiatives.
Thank you, Chris. The overall business is operating well, and our increased investment and focus in the Permian Resources operation is evidenced by the 24% year-over-year growth in total production. Other long-term investments, such as the BridgeTex Pipeline and the Al Hosn Gas project, should also begin contributing to our results in the current quarter. We continue to make steady progress towards furthering our strategic initiatives outlined a year ago. The spin-off of California Resources is on track, and we expect to distribute approximately 310 million shares of new California company to Oxy shareholders at the end of November. California Resources completed its debt financing earlier this month and distributed approximately $5 billion in cash to us as a tax-free dividend on October 9th. The dividend of $1.2 billion in proceeds from the term loan credit facility will happen concurrent with the spin-off.
After the spin-off and for a period lasting up to 18 months, Oxy will retain approximately 75 million shares of the California company. At some point during this period, we intend to conduct an exchange offer for the remaining California shares for Oxy shares, further reducing our own shares outstanding. Over the years, Oxy has made significant investments in California oil and gas and has built a solid business. With the separation of these assets to California, operations will be classified as discontinued. The resulting impact is expected to provide lower unit rates for cash operating costs, DD&A, and F&D costs for Oxy, as well as improved reserve replacement ratios on both a historical and an ongoing basis.
Regarding our interest in the Williston and Piceance Basins, given the current product price environment, we plan to operate these assets with less capital in order to generate free cash and shift our investment towards our higher growth and higher return operations in the Permian Basin. In the Middle East, we continue to make progress in negotiation with our partners towards a partial monetization, with a goal to improve the business's ability to grow profitably from a somewhat smaller base. Over time, we expect to achieve a similar balance in our asset mix, with roughly 60% of oil and gas production coming from the U.S. Over time, we also expect to monetize our remaining interest in GP of Plains All American Pipeline, which is currently valued at more than $4 billion, in addition to some other midstream assets when market conditions warrant.
We expect to generate a large amount of cash proceeds from the initiatives I've mentioned. While we expect the bulk of these proceeds will be used to repurchase our own shares, we also hope to invest in the business through attractive bolt-on acquisitions in our core area of the Permian Basin. Opportunities may exist for accretive property acquisitions that have current production and growth prospects and also complement our existing acreage. We have no intention of acquiring public companies, since their current pricing reflects high oil prices and a near-perfect outcome for production. Since the end of the third quarter of 2013, we have repurchased approximately 31 million shares of the company's stock for nearly $3 billion. The board recently authorized the repurchase of an additional 60 million shares of the company stock, leaving the program with 76 million shares.
We are currently undergoing our annual capital budgeting process and are mindful of the recent decline in oil prices. A significant amount of long-term investment, including the capital for BridgeTex Pipeline and the Al Hosn project, is nearing completion. We expect our overall capital program to decline in 2015, given the absence of California and the completion of multiple long-term projects. We also expect a significant decline in our spending in the Middle East as we begin to reap the benefits of some of our earlier long-term investments. The vast majority of capital budget next year will be allocated to our domestic oil and gas drilling operations, where we maintain flexibility in our budget. We also expect that since the service companies were happy to raise prices when oil was going up, that they would be just as happy to have their prices lower in the future.
Some of the reduction in the program in a long-term project will be allocated to profitable growth opportunities in the Permian Resources, midstream, and chemicals. If lower crude oil prices persist or fall further, we will adjust our capital program to manage within our cash flow, probably by reducing or not growing as quickly in the back half of the year. We plan to provide a more detailed capital program for 2015 during the fourth quarter earnings call early next year. Excluding California, we expect to see an acceleration of total oil and gas production growth in 2015, given the ample opportunity for capital deployment in the Permian Resources and the ramp-up of production from Al Hosn. In the U.S., we expect Permian Resources to deliver production growth of at least 20% in 2015, primarily from oil.
We expect the resources business to exit 2014 at over 80,000 BOE a day and to exit next year at over 100,000 BOE a day. Our total domestic production, excluding California, should grow 5%-8%, reflecting a modest decline in our natural gas and NGL volumes. In the Middle East, first production of the Al Hosn Gas project is anticipated later this quarter. Oxy's net share of production is expected to ramp towards 60,000 BOE a day during the first half of next year. Company-wide and excluding California, we expect our total oil and gas production to grow 8%-10% next year. While the recent sharp decline in oil prices may provide some headwinds to the business in 2015, our commitment to a conservative balance sheet with low-cost oil production gives us confidence in our operations and the capacity to make targeted property acquisitions.
We expect our cash balance to exceed our total debt by the end of this year. Oxy is built to thrive in an environment where our core properties in the Permian EOR business and Production Sharing Contracts in the Middle East, which provides relatively stable cash flow. Following the execution of the California spin-off, Oxy's philosophy of disciplined capital allocation will continue. Our core business will continue to focus on delivering moderate volume growth, generating higher earnings and cash flow per share, as well as improved financial returns. Our Permian Resources business will represent the key area of growth within our domestic operations. I'll now turn the call over to Vicki Hollub for an update on our activities in Permian Resources.
Thank you, Steve. In last quarter's call, I discussed our progress toward reaching 120,000 barrels of oil equivalent per day of production in 2016 by achieving the following goals. First, correlating rock and fluid properties to production performance across Oxy's entire Permian acreage position. Second, optimizing development strategy and design to unlock full primary development potential. Third, efficiently accelerating fulfilled development and production growth. We made significant progress on these goals in the third quarter and continue to improve and optimize our stimulation designs for each field and bench. In addition to testing slick water and hybrid fluid systems, we are testing and analyzing other key variables such as pumping rate, pad volumes, proppant type, proppant concentrations, surfactants, cluster count and spacing, clusters per stage, and alternate technologies to plug and perforate. Our efforts are driving significant improvements in well productivity in our Delaware and Midland Basin assets.
In the third quarter, Permian Resources had daily production of 77,000 BOE per day, which is a 7% increase from the 72,000 BOE per day that were produced in the second quarter. We produced 43,000 barrels of oil per day for the third quarter. This is a 26% increase from a year ago and an 8% increase from last quarter. During the third quarter, our capital expenditures were $472 million. We operated 24 rigs and drilled 75 wells, including 44 horizontals. We placed 71 wells on production, including 36 horizontals. The number of wells drilled and placed on production was adversely impacted by delays attributable to flooding, which occurred in September. This impact reduced the number of horizontal wells placed on production by approximately 10. We've increased the number of frac spreads in the fourth quarter to address the additional carry-in well inventory.
In the fourth quarter, we plan to operate an average of 30 rigs and exit the year with 34 rigs. We expect to drill 80 wells and place 75 wells on production, including 48 horizontals. Before discussing the third quarter activity in greater detail, I would like to share some more information regarding the drilling potential we see on our acreage. Oxy's unconventional plays in the Permian are spread across 2 million acres in the Midland Basin, Central Basin Platform, Northwest Shelf, and Delaware Basin. Our teams continue to utilize our extensive knowledge and appraisal work to characterize prospective benches and target landing zones within each bench. To date, we've identified approximately 7,100 potential well locations. Overall, more than 92% of the locations are horizontal, and our results confirm the economics of horizontal wells exceed most vertical wells.
In the Delaware Basin, we have currently identified 4,250 horizontal locations, with 1,450 in the Wolfcamp A and B benches. The majority of these locations are in our operated areas in Reeves County. The Bone Spring potential is equally as significant, with 1,500 potential locations. These are primarily located in New Mexico and could increase with further success in Texas. In the Midland Basin, we've identified 23 horizontal locations, and 1,050 of these are in the development phase, targeting the Spraberry, Wolfcamp A and B benches. We are highly encouraged with recent results in these benches achieved through our frac design optimization and increases in lateral length. In the Delaware Basin, we operated 11 horizontal drilling rigs and one vertical drilling rig in the third quarter. We drilled 41 wells and placed 40 on production.
In our Barilla Draw acreage, we placed eight horizontal wells on production in the Wolfcamp A and B benches. These wells achieved a peak rate of 1,355 BOE per day and a 30-day rate of 1,067 BOE per day. Our Ryman 14-5H well achieved an average peak rate of 1,600 BOE per day and a 30-day rate of 1,365. We completed our first Delaware zipper frac on the Anna Katherine 5H and 6H, reducing completion costs by $700,000 due to the efficiency gained from simultaneous operations. These two wells achieved an average peak rate of 1,600 BOE per day and an average 30-day rate of 1,225. The production rates achieved on our wells placed on production in the third quarter are significantly above our first half 2014 rates.
This increase is directly attributable to the breakthroughs we are achieving in our optimization program, including increasing sand concentration, lengthening laterals, and optimizing cluster spacing. Our Wolfcamp A wells are matching the 900,000 BOE type curve. Production from our horizontal wells in the Delaware Basin is averaging 89% total liquids, 77% oil. Our appraisal efforts in the Second Bone Spring and Wolfcamp C benches in the Delaware Basin continued in the third quarter. We're excited to see enhanced performance from the Bone Spring and anticipate further gains as we incorporate learnings from the full core we acquired in the third quarter. These learnings will drive improvements in 2015. Additionally, we are encouraged by recent results achieved in the Wolfcamp C. Our Tootsie 206H well achieved an average initial rate of 1,356 BOE per day and a 30-day rate of 912.
In the Midland Basin, we operated eight horizontal drilling rigs and four vertical drilling rigs during the quarter. We drilled 34 wells and placed 31 on production. We are very encouraged with the results in the Spraberry bench and plan to accelerate development of this bench in 2015. During the third quarter, we placed the South Curtis Ranch 3526H well on production. This well was completed in the Lower Spraberry bench and achieved an average peak rate of 934 BOE per day and an average 30-day rate of 913. We have two additional Spraberry wells on flowback with initial production results that look similar to the South Curtis Ranch 3526. These wells are exceeding the 700,000 BOE type curve.
In the Spraberry Wolfcamp A and Wolfcamp B, we placed 11 horizontal wells on production in the third quarter, with a peak rate of 731 BOE per day and an average 30-day rate of 541. Production from these wells averaged 91% total liquids, 81% oil. We continue to gather and evaluate cores, cuttings, advanced logs, microseismic tracers, and pressure data to link reservoir characterization to well performance. We have recently acquired 474 feet of continuous horizontal core from one of our Wolfcamp B wells. This will allow for better definition of lateral reservoir lithologic variations and enable us to tune those differences to open hole logs to optimize placement of perforation clusters and improve frac design. We're making significant progress in our design optimization efforts and are confident this will translate into further improvements in well productivity in upcoming quarters.
For example, at Dora Roberts, we drilled a 10,000-foot lateral in the Wolfcamp B bench. This well, the Dora Roberts 4027H, achieved a peak rate of 1,437 BOE per day and a 30-day rate of 671. This well is exceeding the 650,000 BOE type curve. Additionally, we recently drilled the Hendricks 1H well at Hendrick that achieved an average 30-day rate of 775 BOE per day. In closing, Oxy's program in 2014 is designed to delineate and appraise our acreage in order to maximize both ultimate recovery and financial returns. We continue to make rapid progress translating the knowledge gained in our appraisal efforts to create value from our unconventional acreage. We have positioned the required resources to execute accelerated development in 2015 but maintain the flexibility to optimize our portfolio and pace.
We're on target to deliver 15%-18% production growth in 2014 and remain confident that we will achieve our target of 120,000 BOE per day in 2016. I'll now turn the call over to Willie, who will provide you an update on the Permian marketing strategy.
Thanks, Vicki. Good morning, everyone. I'd like to just take a few minutes to briefly update you on our midstream and marketing strategies in the Permian. It's particularly important in today's market environment to maximize realized value for our production, and our strategy to do so is primarily by ensuring access to markets. I spent some time last earnings call on our midstream strategy to show you how we're trying to develop and secure takeaway capacity in the Permian Basin. I have a slide 29 that shows our strategy, which is really focused on two new key takeaway points, Colorado City, which is the origin of the BridgeTex Pipeline, and Midland South, which is the origin to key third-party pipelines, Longhorn and Cactus. These takeaway points complement our Centurion gathering system by providing us the additional access to multiple markets.
As you're aware, the BridgeTex Pipeline commenced service this September, and together with the startup of some additional pipelines in the next few months, we expect differentials to return to levels that'll reflect the marginal cost of transportation. Slide 30 shows the pricing differentials for Midland WTI versus LLS. During takeaway constraint periods, you can see the LLS Midland differential widened to $30 a barrel and has averaged approximately $16 a barrel over the past four years. In 2014, the LLS Midland differential has averaged $12 year to date, and today, it's currently roughly $10 a barrel. Our unique upstream and midstream perspective to the Permian Basin has enabled us to be a driving force behind the construction of new pipeline infrastructure, as well as takeaway capacity from the basin. Slide 31 shows how we view the key value components for infrastructure projects such as BridgeTex.
As a standalone pipeline investment, we look at tariff revenue to ensure a solid return consistent with our targeted rate of return for domestic midstream projects. This can generate cash of roughly $1-$3 a barrel. Second value driver is when we enter into long-term and cost-advantaged transportation commitments on pipelines as a shipper. This gives us efficient access to markets compared to other transportation routes and options. Depending on the project, advantage tariffs can add another $1-$3 a barrel of incremental value. However, the point I want to make is that the critical value for Oxy is really to avoid discounted prices that result from infrastructure constraints and unplanned outages. The value is significant, and if you look at the past four years, can be $10 a barrel or more.
Our significant takeaway commitment on BridgeTex is a great example of how we capture this value, and in today's market, is roughly $1 million a day for Oxy. Our Permian Basin strategy utilizes all these value drivers to reach multiple markets, and we have secured access to long-term takeaway capacity of roughly three times our current production from the basin. This really positions us well to continue to grow our production, maximize realized prices, and capture market opportunities. I'll turn the call back now to Chris Degner. Thank you.
Hey, thanks, Willie. Denise, we're ready to take questions.
Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. If your question has been addressed and you would like to withdraw from the queue, you may press * then two. Again, it is *1 to ask a question. The first question will come from Evan Calio of Morgan Stanley. Please go ahead.
Hey, good morning, guys. Steve, my first question is, most of your large-cap E&P peers are increasingly looking to live within cash flow or are more limited by their balance sheets. Given Oxy's under-levered balance sheet versus anybody other than a super major, would you be willing to outspend cash flow in a downturn and as a method to right-size your balance sheet? Really, I guess, what is the right or targeted capital structure for Oxy moving forward?
Well, first, I would argue we're better capitalized than the majors.
I think they're over-leveraged myself. Anyway, I think as Chris pointed out, we're going to have a lot of cash at the end of the year from a variety of sources, mostly from the California business. Some of that, of course, will be used to reduce our share count, maybe the bulk of that to reduce our share count. We continue to look for opportunities to grow the business in the Permian through investment. To sum it, while our drilling program may be in line with cash flow, if we see other opportunities to small property acquisitions or even medium-sized ones, we'll use our balance sheet to do those, and those would effectively be an increase in the program in excess of cash flow. I think we've always had a balance of drilling and acquisitions.
It's more shifted clearly to drilling now because we have so much to do. I don't think you'll see massive changes in our leverage, but you will see obviously less equity in our equity count as we buy down a lot of stock. I think there'll always be a balance. If there was a sharp reduction in oil prices that created more buying opportunities, we wouldn't hesitate to increase our leverage to grow the business. I think that from our perspective, this is sort of good times. I sort of know what to do at $75 oil or less, but I have no idea what to do at $120. I think this is really good times for us. May not be good times for people who use this as a proxy for oil price, use our stock as a proxy for oil price.
As a fundamental business matter, see cyclical downturns is where you use the balance sheet to build the business. I'm hoping a lot of happy talk now, especially from service companies, about how this is temporary. I don't know how anybody knows that, but if I could predict oil prices, I'd be sitting on a beach in Galveston, wouldn't come to work, and wouldn't mess with this production business. I think that, as a practical matter, this is a volatile time. There may be a recession worldwide. I don't really know. I don't see that, but a little lower oil prices, I think, could take some of the buoyancy out of it and gives us some opportunities to add to our business.
Our goal is to grow our earnings per share, our reserves per share, cash flow per share through a combination of share reduction and hopefully building the business either through drilling or acquisitions and maybe both.
Clearly well-positioned for a down market. Maybe a related question, on buybacks, you used to have a slide where you built up to 100-million-share buyback, I guess there's two questions. It's not included today, if there's any change in thought there. Secondly, when you did the 100-million share of potential buyback, it was determined when Oxy was $100 a share. It's $89 today. All things being equal, it'll be lower following the CRC spin. At the same time, the elements that are funding the buyback are largely flat, right? I guess, how do you think about that, which is approximately about a billion-dollar delta or is it?
We denominate this stuff in shares.
That's the way we think about it. How many shares are we buying back? We're fairly somewhat disciplined in making sure that we don't buy shares at prices that imply they're excess of our finding and development cost. I think that's the way we sort of look at it. We announce the share repurchases as we actually have the cash in hand.
It's not intended as a forecast of what we might ultimately do. As more cash comes in hand, you should expect that the share repurchase authority would rise. It wasn't the 60 million shares we've had, we got 76, I think, roughly, left to go. You should view that as sort of the cash in hand number, not the ultimate. The ultimate will be dependent on the pace of proceeds from various things. I think we're not trying to forecast. We're not saying this is what we got in our hand now. If it turns out that we have excess money because the price of stock is too low, we'll adjust the share repurchase to higher numbers.
Got it. How do we consider a timetable? Is that for the buyback, given it's significantly higher than a level historically, or is it still just going to be a level-driven program?
It's driven principally by the stock price. We look for buying opportunities in the market when people become irrational.
Got it. Appreciate it, guys. Thanks.
Thank you.
Our next question will come from Doug Terreson of ISI. Please go ahead.
Good morning, everybody.
Good morning.
Steve, I have a couple of questions about the MENA E&P business. First, from a strategic perspective, there's been commentary about divestitures in Oman and other countries. Whether or not you comment on assets individually or the position in MENA in general, I wanted to see if we could get an update on likely strategic outcomes there and/or the environment for monetization in MENA in general, which you've talked about in the past. The second question is if you guys mentioned that Al Hosn is going to start up on time in the current quarter, which is good. The second question is whether it's going to come in on budget as well. Two questions.
The second, we'll have Sandy answer the budget question, but it's a sort of one-word answer. On the overall reduction, it's sort of one at a time.
Yeah.
Our objective is the same, one way or another, to get value out of the Middle East business, some by selling it and maybe some by speeding up the cash out of the asset where it's more difficult. One way or another, we're basically using the business to downsize the size of that business, make it less important in the company. Still an important part, but it's going to be a lot of cash is going to come out of that business one way or another over the next few months.
Okay.
I think we're going along. It's slower than I would like, of course.
Yeah.
To some extent, by showing being too anxious, sometimes you get a worse result than you might get some other way.
Right.
Sandy will answer the question on budget here.
Okay.
The answer is one word. Yes, we are on budget. It's a well-planned project and well-tended. The startup sequence has been initiated, and we expect to have some product sales in the quarter.
Great. Thanks a lot, guys.
Thanks.
Our next question will come from Doug Leggate of Bank of America. Please go ahead.
Hi, thanks. Good morning, everybody. Steve, I also have two questions. I guess my first one's for Vicki. I really wanted to talk about the Permian or ask you about the Permian growth trajectory that you've provided for us. Your run rate since you ramped up the rig count has been about 5,000 barrels a day per quarter, and I realize it's very simplistic just to look at the absolute move sequentially. You are significantly accelerating the rig count and the backlog, it looks like. I'm just trying to reconcile a substantially higher activity level with a similar quarterly rate of growth, at least implied by your projections for the next couple of years. That's my first question. I've got a follow-up, please.
I'll let her answer the question, I think I wouldn't confuse our expectations with our promises. There's probably a wide difference between them. Go ahead, Vicki.
Yeah, Doug, originally, we had not planned to reach the exit rate this year with 34 rigs, we've accelerated our development a little bit. As you've noticed, we're a little bit behind on some of our wells completed, we've added another couple of frac spreads. Now as of 1st of November, we'll be at seven to address the well inventory. With respect to the rigs going forward, we still intend to stay somewhat as per the schedule that we had showed in our last presentation. We're just seeing a little more opportunity here to get a little bit ahead of the game.
This isn't a working interest issue or anything like that, Vicki, in terms of subsequent wells from here having a lower working interest. Maybe you could give us an idea of what that average working interest is. Thanks.
Well, we kind of gave you an indication on the slide in the presentation that for the Midland Basin, generally speaking, our working interest is close to 92% overall. In the Delaware Basin, around 76%, generally speaking.
Okay. Thanks for that. Steve, my follow-up is really, I realize we're going to have to wait on the capital for the end of the year, but just as an order of magnitude, I wonder if you could help, given all the moving parts with California gone, BridgeTex and Al Hosn largely done. What I'm really trying to get at is how you think about balancing spending with the dividend as opposed to asset monetization funding the buyback. How should we think about dividend policy and maybe a broad scale of spending for next year, if you could? Thank you.
It's hard to do the budget right now because there's a number of moving parts, we have to talk with our partners in the Middle East about the size of the program there, I'd just as soon not telegraph our thoughts right now. I think our Permian program, certainly for the first half of the year, will be what we told people it would be. I don't expect any real change in that. Some of the other stuff may be tweaked a little bit in some of the other programs. We just don't know. As far as the dividends are concerned, I think you go back to the slide we've only shown for, I'm going to say 10 years, but I think Chris is shaking his head that it's more.
It says, after maintenance capital, which is making the company safe, the next line is dividends, before growth. We view our commitment to the shareholders on dividends to be part of our overall commitment. How much exactly you're going to raise the dividend by remains to be seen. There's obviously a little confusion with the lower oil prices. We've raised the dividends, I think, for 12 years. I don't think we're going to break the chain next year. I assume the dividends will go up. We've got a lot of cash and a lot of projects to fund almost anything we want to do. I don't think anybody should be concerned. I think we're focused on making sure that the drilling program delivers the results it's supposed to deliver.
If it delivers the results it's supposed to deliver, there'll be plenty of money over the next two or three years for dividends, dividend growth, continued dividend growth, and share reduction and lots of growth in the business. If we deliver the results that we're doing so far and our plans are pretty much on target, there'll be plenty of cash flow, and I don't think anybody should worry about where it'll be a couple of years from now. Next year's going to be a messy year. You get comparisons against a company with different set of assets. They're going to have some sales of things next year. The share count is going to be really confusing.
For example, the pro formas now for this year use the average shares outstanding for the year to do the EPS calculation, which is a lot more than the shares outstanding right now, never mind at the end of the year. I think if I were looking at the company, I would focus on our program in Permian Resources and our cash generation in the rest of the business, and I think we've now fixed the realization issue out of the Permian Basin that we faced the last three or four years. Unfortunately, we may have fixed it for everybody in the basin, but we fixed it for ourselves. I'm pretty optimistic about where we are next year.
Great. Thanks a lot, Steve.
Thank you.
The next question will come from Leo Mariani of RBC. Please go ahead.
Yeah. Hey, guys. I was wondering if you could address a little bit more the comment that you all had made about potentially moderating activity. I think the phrase you guys used is if oil prices stay here or move lower, and you referred to the second half of 2015. Is there any more granularity you can give around that? I recognize the budget's not done yet and there's moving parts. I know you have ambitious plans to ramp up the rig count in the Permian. Is there any scenario you can paint whether or not you stop ramping rigs in the second half of the year? Would you actually drop rigs? Can you maybe just talk through that a little bit?
I don't think we have any plans to drop rigs. The ramp rate is what we would fool with because the business is we continue to drill wells, put them on stream, generates cash, more cash than some people are out looking. I think we'll be okay, and we certainly have the financial flexibility to weather that. On a long-term basis, we're fairly optimistic about oil prices. Over the next year or two, I don't know. I think on a long-term basis, despite what people say, the U.S. business is not healthy at $70 oil. I think higher oil prices are in the cards over time.
Okay. I guess just in the Permian, could you guys maybe talk to what type of well costs you're seeing on the Midland side as well as the Delaware side?
Yeah, Vicki can probably answer that.
Yeah, depending on the depth, in the Midland Basin, we're seeing well costs that are in the $7 million to $7.5 million range for our South Curtis Ranch and some of the areas around that. In the Delaware Basin in Texas, we're seeing well costs in the neighborhood of $8.6 million to $8.7 million. Our drilling costs have been improving through some of our efficiency initiatives, but it's really the completion costs that are driving our total well cost right now. What we've done recently is increase the size of our frack jobs, which is giving us better productivity and what we think will be better ultimate recoveries. When you're seeing higher well costs for us, it's because we're increasing the size of our fracks.
That's helpful. Is there any kind of approximate lateral length you can put around those well costs at all?
Around the 8.6 to 8.7, that's generally a lateral length of about 4,500 to 5,000. In South Curtis Ranch area, our lateral length is around 6,100.
Okay. That's helpful. In terms of your Bakken and Piceance assets, I guess you had it in your slides that you guys plan to limit capital there. Could you talk about longer term plans for those assets? I know you'd spoken in the past about selling the Bakken properties and also putting the Piceance assets into a JV for maybe an eventual IPO. I guess you also talked about additional midstream sales when market conditions warrant. Can you maybe just talk through strategically how you're thinking about those assets?
Well, the issue in the Bakken is it simply can't compete for the returns that are being earned in the Permian. It's not that they're bad assets or anything, it's just not competitive in our portfolio. The Piceance is all gas, and gas is tough to compete in this environment. We'll be. I don't see any way to change. I'm not bullish about gas prices. I don't see any real way to change the relative competitiveness of North Dakota versus the Permian. We can move oil out of the Permian by pipeline. That's a much more efficient way to move oil than by train. I just think that it's, just will not, for our portfolio, won't be able to compete. Ultimately, we'll have to deal with that.
All right. That kind of implies an eventual disposition, I would assume, at some point.
Yeah. Sure.
Okay.
Right now it's a little noisy because
Yep
It's probably not the perfect time to be doing that.
Okay. Makes sense. Thanks, guys.
Thanks.
The next question will come from Ed Westlake of Credit Suisse. Please go ahead.
Yes, good morning. An intriguing comment from you there, Steve, just on saying cash flow is being underestimated. Obviously, oil prices make it a lot of volatility, but maybe some color on that. Is that because you think your promise is going to be exceeded by your expectation on volumes? Do you think it's because cash margins are being underestimated as you shift to drilling in the Permian? Is it Al Hosn or is it all three and something else?
Generally, I think people have underestimated the cash flow that'll come out of the assets. They basically take what we did this year and add 2% or something to it, then adjust for price. The Al Hosn project will certainly add. There's other things that I think will add, but I think we show you, I think, in this. We look different without California. We give you some numbers to help you model that. We don't know what the DD&A rate will be next year because it depends on reserves. The underlying DD&A rate, for example, without California, U.S., is lower. Same thing with operating costs and other things. I think people are just sort of taking the old numbers because that's really all they had.
I think as you look at it, maybe a little more careful modeling with the new numbers might be more helpful for people.
Okay, great. A question on the Permian. Obviously, if you look at the Midland, you've outlined Dora Roberts, South Curtis maybe. These are sweet spots in the northern Midland, but it's not a huge amount of acreage, but it will be very productive. In the Reeves Barilla Draw area, you've got this fantastic result again, and that's obviously a larger acreage position. That drives growth over the next five, maybe six, seven, maybe even longer years. When I look at the rest of the Permian, and particularly, say, if oil prices did have a longer excursion to the downside, how do you think the returns stack up? I'm particularly, say, looking at the New Mexico, Delaware. What's the sort of break-even oil price you need for getting an acceptable return to drill there?
Well, I get to take a longer view, I guess because it's a smaller proportion of my age. If I look back two, three years ago, what we thought about the Permian Basin and what we thought internally, forget what other people were saying, I look at the programs that have been proposed now, it doesn't even look like the same company. I think as we progress, we continue to find new things that we didn't think of before, that will add considerably. I think the business, ultimately, if oil prices stay low, whatever you want to call the current price or at this level or lower for an extended period of time, margins historically have adjusted by the reduction of service costs.
You're not going to get an environment where oil prices stay at, say, $75 or whatever you think for four or five years and service costs are going to be the same. It just isn't going to work. Part of the gain sharing and loss sharing here will be in from both parties. All the money isn't going to just go in the service company coffers and we're going to work for free. Not just we, but everybody. I think in the end it'll equilibrate and we'll generate acceptable returns. We think there's a lot of economic oil at $75. Economic meaning we earn 15, 16, 17% returns. Do I think there's a lot of economic oil at $50? No, I don't. Somewhere in that range, but it also depends on service costs.
If oil prices go back to 100 or whatever again, service costs will rebound with that. I just think that this thing will work itself out over a one or two year period. I hate to say it this way, but I look forward to a little stress and some of the crazy stuff goes away for a while, and that gives rational people an opportunity.
A final question just on the 2015 production outlook. That's very helpful. 8%-10%, and you can see, obviously, the great contribution from Al Hosn, which will probably still have a bit of tail end contribution maybe even in 2016 as well.
That's right.
Obviously, reducing activity in the MidCon. It seems from the well results and the activity level, do you think the Permian can provide an offset to keep that production growth at a similar pace in 2016? Or does it just naturally slow as Al Hosn comes down?
Al Hosn will eventually flatten.
That's something I think is great on Al Hosn.
Yeah. I think at Al Hosn, I think it's possible that over the next few years, the plant is larger than it needs to be for the deliverable gas. The country continues to need gas there and the result in liquids, of course. I think over time, there'll be an expansion probably, and it's definitely up to the government. Al Hosn is not through. I think as we look at 2017 and 2018 and 2019, we'll see more growth out of Al Hosn. At some point, it'll level off, that's true. I think it'll probably continue to grow, because once you've spent the base money, the incremental capital will have really good returns, I think.
Yes.
I think that'll do better. I think the Permian Resources business has the potential to cover, to continue to grow and maybe grow better going forward as we work through some of the historical issues. I think we've got more acreage, and I think more will prove up. The Barilla Draw didn't really exist a year ago. The land did, but the concept didn't exist. I think there's a lot of good concepts out there. Some will work and some won't. Some are I think over-promoted by some. It's hard to imagine that on 100,000 acres, you're going to have 4 billion barrels of reserves. I think rational expectations are good for the basin. I think the Permian Basin is the best basin in the U.S. and will be for the next 20 to 25 years.
Thanks very much.
Thanks.
The next question will come from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.
Good morning. First question I wanted to ask refers to slide 27, the SCR3526H Spraberry well. Is the early shallow decline consistent with your expectations, and does this early positive result have any influence over your Spraberry appraisal plans going forward?
Yeah, we're still evaluating that South Curtis Ranch 3526, and the shallow decline on that is so far good news for us. We still want to see a little more production data from that to determine what's causing that.
Great. Thank you. Just as a broader question, just looking at your plan as it's unfolded in Permian over the last several quarters, it doesn't really appear to encompass the Central Basin Platform, where some peers have drilled some noteworthy horizontal wells. I was wondering if you have any horizontal exploration potential in that area.
We feel like we have a lot of potential on the Central Basin Platform, and that's just one of the areas that we have yet to get to. We're working on a fairly structured plan with respect to our exploration, our appraisal, and our development programs. What we showed you on the slide that has the breakout of the zones that are currently under appraisal and currently under development, that list does not include what we're doing from an exploration standpoint. Our exploration group, one of their key areas to focus on over the next couple of years will be the Central Basin Platform, where we do have significant acreage, and we think there is a lot of potential there. It just hasn't gotten in the queue yet, but it's something that we're optimistic about.
That's a nice problem to have. Thanks very much.
Our next question will come from Roger Read of Wells Fargo. Please go ahead.
Hi. Thank you. Good morning. Hopefully I'm on. A quick question. On the OpEx side, a couple of years ago, started an OpEx reduction effort, obviously, it was successful. This time around, talking about OpEx, last night on the call with CRC, they talked about higher gas prices. I was wondering, ex California, if you could walk us through what the OpEx issues are here and how much of that is due maybe to just temporary gas price increases, and how much of it is a function of maybe changes in what you're doing in the Permian Resources area?
Just as you look at OpEx, I think there's a cost of energy which is buried in OpEx because we use a lot of electricity to run pumps and such. Some of that's in energy, and some of it is basically driven by the EOR business, where the gas to CO2 is tied to oil price, and they use a little more CO2, and we expense that. It shows up as an operating cost. Some of it is we've increased the workover activity, principally in the EOR business. When you look at our numbers for operating costs in the U.S. The overwhelming driver is the EOR business, which is basically a low capital business, but a little higher operating cost business than, say, the resources business, which is a high capital business and a low operating cost business.
What you see is, as we put more CO2 in the ground, as we try to repair the wells, you get more operating costs. We try to optimize that. What we look at is the base, the underlying operating costs, not so much what we're doing from quarter to quarter. We can't do anything about the CO2 prices or anything like that. I think it's a mix of things, but the driver for operating costs for Oxy, excluding California, is the EOR business, which is a large business, and its principal expenses are not capital, but rather operating costs. It just looks a little different than you might be used to.
With California soon to be gone.
Yeah. We actually show you somewhere. Chris?
Yeah. We gave you a pro forma slide table in the IR schedules that shows pro forma without California and the Hugoton for cash operating costs, DD&A, and some other metrics and also production. You sort of can go back and model it off of that, and you'll see what happened over that period of time.
Okay. We'll do that. Then, the other question I had was along the lines of catching up on the well completions, and the addition of the frac spreads in West Texas. Any chance for upside performance in terms of production there, relative to the guidance, or is that all fully incorporated in the numbers?
That is incorporated in our projections for production. We do expect to catch up, and we've accounted for that.
Okay.
I think what he's asking is, have we been conservative in the number or not?
Based on the performance we've seen thus far, I'd say that's a conservative number, actually. It's an achievable number.
Okay. Well, that's very helpful. Thank you.
Our final question will come from Paul Sankey of Wolfe Research. Please go ahead.
Thank you. Good morning.
Morning or whatever it is.
Yeah. Afternoon, I guess. A couple of high-level strategic questions. Firstly, do you think you've been behind technically in the Permian? Do you think you can get ahead, and do you think any kind of technical advantage is sustainable in U.S. unconventional given the commoditization of the activity?
We'll start with, yeah, we were behind. I think somewhere earlier I said, if I look at what the presentations internally were two years ago, and I look at the quality and the detail of the current presentations for next year's program, doesn't even look like the same company. I think we've made a lot of progress. We're blessed with good acreage, which compensate for whatever, to some extent. I always believe that it's the acreage or the reservoir that overwhelms over time technology, because technology spreads quickly. I don't think there's some secret sauce that lasts very long. I think as a practical matter, I think we're where we need to be in technology. There's always going to be improvements. Whether you have relative improvements against other people, I don't know.
Over time, the technology spreads very quickly, because we see lots of wells, so it's not really something that's hidden from us. I think we're where we need to be from a skill set at this point. We were behind, there's no argument about that. We are fortunate that we have an exceptional acreage position, which, in the end, the reservoirs matter.
I guess the argument there would be that you were in early, relatively speaking, and paid less, but above all, the early entry allowed you to get the better acreage. Is there any other proof, by the way, that you have better acreage? I mean, how can we show that?
Well, maybe Vicki can tell you about that.
I'd like to build on Steve's comments with respect to your first question initially. Technically, we have teams here with Oxy that I think could compete or beat any other teams in the Permian Basin at this time. From a success standpoint in the unconventional plays, one of the critical things is to understand what the reservoir is and what the reservoir's telling you. We don't believe that these plays should be called statistical plays. We think that you've really got to understand what the reservoir is, and based on what the reservoir is, you design your completions and your frack jobs. I think right now, we're probably one, if not the only company, one of the few companies that's actually taken a horizontal core.
Along with our vertical cores, our 3D seismic, our microseismic, and all the additional work that we're doing around reservoir characterization, I think nobody in the basin is any further along than we are with respect to that. I think with that said, the industry as a whole still has a lot to learn. We're all very early in the development of these unconventional plays in the Permian. I still think that we're going to continue to learn. Technology will continue to advance. I think that, as it does, I expect over time for cost to come down on, at least from the drilling standpoint And possibly from the completion standpoint.
We've got some plans in place over the next six months to do some things, I think, that could have a significant impact on our productivity and ultimate recoveries, but it's just a matter of working those costs to make sure that they're economical for what we want to do. As I said, technology over time, the cost comes down, and so I think we'll be able to do some things that will certainly help some of the areas that previously have not been as good as our Delaware Basin area. I'm sorry, now I've forgotten your second question.
No, I'm just saying if there's some way that we would be able to show easily that your acreage is superior to someone else's.
Well, we've got so much of it that some of it's going to be better and some not. If you compare it to some guy that's got 100,000 acres and that's his whole position, who knows? I think if you look at the overall result and you say we started from a standing start two years ago, and we'll pass 80,000 at the end of this quarter, and we'll pass 100,000 by the end of next year, for sure. I just look at, from a standing start two years ago, we'll be one of the biggest producers in this unconventional in no time, when our whole business historically had been an EOR business. It's whatever you want to think, but I think there's always somebody who's got 40,000 acres that's real good. The question is, can you have 2 million acres that's real good?
I think we got enough 40,000-acre pieces that we could compete with anybody. If we took one of our 40,000-acre pieces or 100,000-acre pieces, and people were saying what a wonderful company it is, it's as good as the Snake company or whatever it's called.
Got a couple of quick ones, Steve. The investment in midstream is simultaneous with the sell down of the GP of Plains All American. I assume that means that you wouldn't be continuing to want to own those assets long term. Further to that, does the deliberate naming of Permian Resources rings a bell with California Resources? I wondered if that was a potential spin candidate, and I'll leave it there. Thank you.
On the midstream, our goal is to, I think as Willie pointed out, our goal is to make sure that we get the best possible price for our product and we're not disadvantaged. We've gone through several years of disadvantage. If we can do that without spending capital to build pipelines, we're happy to do that by committing for space and reaping the advantages of owning space. I think you should view it as its purpose is basically to make sure we get good prices for oil. If we could monetize, take back some of that capital some way and put it somewhere else with higher returns, we're definitely going to do that. As far as the name is concerned, it's sort of an accident.
I wasn't all that wild about the California Resources name, but I don't think you should view it as a spinoff candidate at this point. It needs right now the cash flow from the rest of the business to accelerate its drilling. It's unlike California. California is actually some good business. It's at a mature phase where it can be self-financing. The resource business needs cash to grow, and it's just not the right time to even think about something like that.
Thank you very much.
Thanks.
Ladies and gentlemen, this will conclude our question and answer session. I would like to turn the conference back over to Chris Degner for his closing remarks.
Yes, thank you everyone. Please give us a call if you have any follow-up questions. Have a good day.
Ladies and gentlemen, the conference has now concluded. We thank you for attending today's presentation. You may now disconnect your lines.