Marathon Oil Corporation (NYSE:MRO)
December 11, 2013 8:30 AM ET
Howard Thill - VP - Corporate, Government and IR
Lee Tillman - President and CEO
Lance Robertson - VP, North America Production Operations
Mitch Little - VP, International & Offshore Production Operations
Annell Bay - VP, Global Exploration
J.R. Sult - EVP and CFO
Arjun Murti - Goldman Sachs
Ed Westlake - Credit Suisse
Doug Leggate - Bank of America
Blake Fernandez - Howard Weil
Paul Sankey - Deutsche Bank
John Herrlin - Societe Generale
Evan Calio - Morgan Stanley
Guy Baber - Simmons & Company
Matt Portillo - Tudor, Pickering, Holt
Mike Kelly Global Hunter Securities
Krim Delko - Orange Capital Partners
Jay Saunders - Jennision Associates
Good morning. I am Howard Thill, Vice President of Corporate, Government and Investor Relations for Marathon Oil Corporation, and I would like to welcome you to the 2013 Analyst Meeting. The synchronized slides that accompany these presentations can be found on our website at marathonoil.com and on our MRO app for mobile devices. We’ll also be live tweeting today on Twitter and StockTwits, hash tag MROAnalystDay. You’ll see from the agenda, I will put up on the screen. I am, it’s not working. You have me unlocked.
You’ll see from the agenda, on Slide 3 that we have a full slate of presentations followed by a question-and-answer session. We expect the presentations to take well less than two hours and then we’ll move directly into a question-and-answer period. During the question-and-answer session, we will take your questions, both from the live audience here in New York, as well as from the Internet link at marathonoil.com. For those in the audience today, please wait for the microphone and then state your name and firm affiliation.
Slide 4 contains a discussion of forward-looking statements and other information including this presentation. Our presentations today, and answers to questions today, will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.
In accordance with the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its Annual Report on Form 10-K for the year ended December 31, 2012, and subsequent Forms 10‐Q and 8‐K, cautionary language identifying other important factors, though not necessarily all such factors, that could cause future outcomes to differ materially from the forward-looking statements.
With that, I’ll turn the podium over to Lee Tillman, President and CEO of Marathon Oil Corporation.
Well thank you Howard, and good morning everyone joining us today here in New York, and of course to those listening via webcast, especially our Marathon Oil employees around the world. We appreciate your interest in Marathon Oil and today we plan to share a comprehensive update on our strategy and business plans to profitably grow volumes and generate competitive returns for our shareholders.
I am particularly pleased to be joined by other members of Marathon Oil’s senior leadership team and feel confident that you’ll benefit from the interaction with a broader group during the presentation, as well as the question-and-answer.
As you saw on our news release this morning, we announced three significant priorities for our 2014 business plan. First, we are accelerating rig activity in our high-quality U.S. resource plays. We’re increasing our rig count in the Eagle Ford and Bakken by 20% each, and doubling our rig count in the Oklahoma Woodford.
The accelerated 28-Rig program is underpinned by 2.4 billion oil equivalent barrels of 2P unconventional resource, a number which has doubled since 2011. It is also supported by over 4,500 net well locations. To support this acceleration activity, we have set our 2014 capital and exploration budget at $5.9 billion which allocates over 60% of capital to the resource plays. And the resource plays alone expected 2014 production growth is forecasted at over 30% from 2013, and overall production growth is expected to grow approximately 4% ex-Libya.
Angola and Alaska and of course all of those compared to about 10% growth from 2012 to 2013. So the period 2012 to 2017, our resource play compound annual growth rate or CAGR will be greater than 25% and overall production CAGR will be 5% to 7% for the same period with the acceleration of higher margin resource plays offsetting our exit from Angola.
Second, we plan to market our UK and Norway assets as part of our continuing and rigorous portfolio management. A sale of these assets would simplify and concentrate our portfolio to higher margin growth opportunities and increase our adjusted 12 to 17 compound average growth rate to 8% to 10%, a significant increase from our current guidance of 5% to 7% CAGR for the same period.
We will take a broad and integrated approach to marketing these quality assets to maximize the value to our shareholders. For your reference, in the past three years we have closed or agreed upon nearly $3.5 billion in non-core asset divestitures, surpassing the upper-end of our stated $1.5 billion to $3 billion target.
The third priority for 2014, our Board of Directors has recently increased our remaining authorization for share repurchases to $2.5 billion. As a reminder, we completed $500 million worth of repurchases in September or about 14 million shares and have another $500 million planned once the Angola Block 31 sale closes. When that tranche of repurchases has been executed, we will have $2 billion remaining in share repurchase authorizations, which will provide further optionality for the use of any sales proceeds.
These three priority actions reinforce our overall strategy and our commitment to rigorous portfolio management coupled with robust capital allocation. They are essential steps to Marathon Oil becoming the industries’ premier independent E&P Company.
I would now like to step back and put those 2014 tactical actions in the context of our overall strategy. In 2011 Marathon Oil became an independent E&P Company. And in order to be recognized as the premier independent, we must and will excel in these seven areas; first, living our values; second, investing in our people; third, continuous improvement in operating and capital efficiency; fourth, driving profitable and sustainable growth; fifth, rigorous portfolio management; sixth, quality and material resource capture; and finally, seven, delivering long-term shareholder value.
Converting these seven drivers to becoming the premier independent E&P Company into actionable priorities, we arrive at these strategic imperatives that we believe will differentiate our Company. I will use these strategic imperatives as the framework for the remainder of my remarks, and they will also be built upon by subsequent presentations.
First and foremost, we will maintain an uncompromising focus on core value, which are fundamental to protecting our license to operate and our ability to create shareholder value. At the very top of the list is our commitment to safe and responsible operations. We believe our differentiated safety performance promotes Marathon Oil as a partner and an operator of choice. A safe business is a well run business.
For the lagging indicator of total recordable incident rate, Marathon Oil’s performance relative to industry data from member companies of the American Exploration & Production Council is outstanding, and leaves no question that we consider safety first in all that we do. However, we will not be satisfied until no one is injured on our operations and we will continue to work toward elevating the safety performance of the industry as a whole. There is nothing propitiatory about safety, and we will share our learnings and experiences to help promote safety excellence with our contractors, our partners and our other operators.
This chart -- sorry, we recognize that while safety is our first job, there is a strong demonstrable correlation between safety and business performance. This chart shows safety performance, or TRIR, and unplanned production losses overtime for our international operations, which were lead by Mitch. And the relationship is clear. Our safety and integrity focus captures value through higher reliability or lower unplanned losses. As we improve safety, we improve our business. And in the case of reliability these are our most profitable barrels.
The second strategic imperative is investing in our people, growing and maintaining our capabilities and competencies to ensure our shareholders have access to the full global opportunity set. Our human capital is our most important resource and our ability to attract, develop and retain the upstream critical skills to execute our business is essential. And Marathon Oil has the collective capability and capacity to be successful across the complete range of opportunities from resource plays, to offshore, to international, to the most complex upstream developments.
It is our belief that when Marathon Oil wears the operator hat, we can -- and can bring the full impact of our dedicated employees and contractors to bear, we will generate incremental value for our shareholder. And in so doing we’ll be recognized as a developer and operator of choice both domestically and in the international arena.
Our first strategic imperative is the relentless pursuit of operational and capital efficiency. I’d like to begin with operational efficiency. Looking at 2012 unit cash cost per Boe relative to our peer group and using a 22 to 1 gas to oil ratio to normalize for operational complexity, as well as value Marathon Oil is well positioned as a low cost operator.
Our favorable position reflects our commitment to expense management and maintaining a competitive cost structure relative to our peers. And we’re not resting on this absolute performance, but continue to evaluate and implement actions to reduce cost and become more efficient. We will never be satisfied with our cost performance and our asset teams understand the need to push everyday on this all important metric.
Staying with the theme of expense management, the chart on your left shows that our North America E&P segment cash cost per Boe, which excludes oil sands mining have decreased 14% from 2012, when compared to the first nine months of 2013. On a total E&P basis as shown on the right, which includes our mature international assets that are typically challenged by declining production, we have been able to maintain very low absolute unit cash cost at less than $13 per Boe, as well as drive continuous improvement though at reduced levels from our growth areas.
We recognize that unit cash cost must be worth for both the numerator and the denominator and that operational efficiency must be a focus throughout the lifecycle of an asset.
Shifting to capital efficiency, our most compelling example comes from the resource plays. While improving capital efficiency across our operations is important, accelerating the learning curve in the resource plays is critical because the learning can be applied across 100s of wells, generating a multiplier effect with real impact on overall capital deployed. Less capital means lower non-cash cost to be amortized over the life of the field.
In just the last two years, we’ve reduced our drilling times in the resource play significantly, achieving a 50% improvement in the Eagle Ford and a 33% improvement in the Bakken. Our fourth strategic imperative is to accelerate resource development to optimize value, grow profitable volumes and replace reserves.
First, from a value perspective, Marathon Oil has successfully driven its portfolio to higher margin liquids. Our sales through third quarter 2013 were greater than 70% liquids, which is top quartile among our peers. Our clear bias toward liquids in our existing production and in our forward growth favorably differentiates us.
Moving to profitable volumes growth, as we have communicated externally in the past, our resource growth coupled with increased activity and strong legacy asset give us confidence in our ability to deliver on our 5% to 7% compound annual growth rate target. While this slide contemplates the increased activity in our resource play, and a return to normal operations in Libya in 2014 it also removes approximately 30,000 barrels per day of production from Angola in 2017.
Adding back to the Angola production the target CAGR would have been more 6% to 8%. And as a reminder, the 5% to 7% growth rate does not include additional acquisitions, dispositions, or exploration success. I would also like to point out that the lighter shading in the forecast bars represent a risk range of volume outcome and this convention will be used throughout the presentations today.
Staying with profitable growth, the acceleration of our investment in our three high-quality resource plays is the primary contributor. As I mentioned in my opening remarks, we are increasing our drilling activity in the Eagle Ford and Bakken 20%, and doubling the rig count in the Oklahoma Woodford. The three resource plays have combined to grow volumes 300% from first quarter 2012 to estimated fourth quarter 2013.
Supporting profitable growth requires the addition of new resources that can ultimately be migrated to reserves, through optimization, down spacing, and co-development of other horizons we are adding material 2P resource to the domestic resource plays. As Lance will detail further during his presentation, we are capturing the benefits of down spacing and optimization with the South Texas Eagle Ford, for example, drilling its 2P resource from an initial acquisition level of 469 million net oil equivalent barrels to 1 billion net oil equivalent barrels today.
Lance will also detail the aggressive pursuit of co-development, both in the Eagle Ford and the Bakken where we co-develop other horizons in parallel with the main horizon. This approach is illustrated here with the co-development of the Austin Chalk upper and lower Eagle Ford. Though we are still in our early days, we are seeing some very encouraging results.
Our fifth strategic imperative is rigorous portfolio management integrated with robust capital allocation. An optimized portfolio is a necessary step prior to allocating capital. Beginning with portfolio management since 2010, we have completed or announced sales with a total transaction value of $4.8 billion. We have no sacred assets and we’ll continually test all assets as to their profitability and fit within our portfolio. Our decision to market an asset will be based on many factors and unique to the specific financial, operational, market and risk management considerations for that asset. We do not enter into a marketing decision without first, that comprehensive view of how that decision will create value for our shareholders.
The announced marketing of our North Sea assets in the UK and Norway is a continuation of our rigorous portfolio management. The assets involve and include the Operated Alvheim development, the Operated Brae field and the non-operated Foinaven development.
The material contributors to our 2012 E&P volumes accounting for some 20% of production, these assets represent only 3% of both our 2P and total resource. Successful marketing would simplify our portfolio while providing a higher rate of growth.
From a shareholder perspective the successful marketing of North Sea and the North Sea asset provides multiple advantages; first, it would increase our adjusted compound average growth rate for 2012 to 2017 to 8% to 10% from 5% to 7% as illustrated in the upper plot, as well as accelerated cash flows; second, it would simplify and concentrate our portfolio to higher margin opportunities as shown in the operating cash flow chart in the lower plot. The operating cash flow contribution of North America moves from 70% to 80% in this successful marketing case.
The timing of this marketing is reflective of where we are in the lifecycle of this asset, and the work we have done to fully understand their potential and remaining upside. Our marketing approach will be broad to ensure that we maximize shareholder value. And if successful, we would have optionality in the use of the proceeds.
Complementing our rigorous portfolio management we are committed to robust capital allocation with a clear concentration on high growth higher margin opportunities. Of our $5.9 billion in CapEx for 2014, we plan to allocate more than 60% of that to the U.S. onshore resource plays, the Eagle Ford, the Bakken, and the Woodford. That’s fully consistent with the acceleration of drilling activity that I discussed earlier.
Our sixth strategic imperative is the capture of quality and material resource. As an E&P Company, there is no greater challenge than access to new resource. We can achieve this access really in two ways, by the bid through our focused exploration program or by the wallet through opportunistic business development.
I would like to start with our focused exploration program that we have tailored to very well defined, risk criteria. As Annell will later detail, our renewed exploration program is focused in four oil-prone areas; Kurdistan Carbonates, the East Africa Rift, Pre Salt Gabon, and the Gulf of Mexico. These basins have common attributes that meet our risk criteria as illustrated in the center circle, improving our emerging basins, oil-prone and they are opportunities where Marathon Oil can drive value and pace as the operator. This renewed program is already having success with multiple discoveries announced in 2013 including Pre Salt Gabon and Kurdistan.
Also supporting resource capture, Marathon Oil has been very successful at leveraging business development. We have addressed the importance of rigorous asset management from a divestiture standpoint, but equally important is being opportunistic as discovered resource becomes available in the market. Quality, materiality, selectivity, economics and risk, all come into play, but business development is an important growth lever.
Case implying more than 50% of our 2013 production volumes through the third quarter, our source from three key assets we obtained through strategic business development. Eagle Ford, Norway, and EG, are all business development success stories and you can see that since 2011 we have continued to bring accretive opportunities into our portfolio.
The key quality test for resource capture is the ultimate migration to prove reserves, and Marathon Oil has a line of sight on greater than 100% reserves replacement. For 2013, we estimate that our reserve replacement ratio will be greater than 140%. And historically for the period 2010 to 2012, we have replaced over 170% of our production.
Marathon Oil has a 2 billion oil equivalent barrel proved reserve base that is over 75% liquids and a 2P resource base in access of 7.5 billion oil equivalent barrels.
Our seventh and final strategic imperative is delivering competitive shareholder value. We do this through a disciplined use of capital sourced from strong cash flows. As the pie chart illustrates for estimated 2013 uses of capital, we are committed to funding organic reinvestments, capturing quality and material resource, paying a competitive dividend, maintaining our investment grade balance sheet, and pursuing opportunistic share repurchases.
And for 2014, our capital needs are substantially funded from our operating cash flow with North America contributing about 70%. J.R. will focus his remarks on our financial strategy and how we will use this to drive shareholder value.
To conclude my remarks I want to reiterate the seven strategic imperatives that I believe underpin the compelling investment case for Marathon oil. All of these will be further amplified in this morning’s remaining presentation. Not only achieving, but excelling across these imperatives is our corporate strategy and the roadmap for how we plan to become the premier independent E&P Company.
Now I would like to turn the podium over to Lance Robertson, Vice President of North America Production Operations. I will return a bit later to wrap-up today’s presentation and open the Q&A.
With that, Lance, please?
Thank you, Lee. It’s great to be here this morning. I appreciate the opportunity to address the group and really excited to share, I think, a compelling body of work demonstrated largely by a great set of teams we have in our North America assets.
And as I -- starting on Slide 29, where we talk about where we are today, I think I would like to reiterate a key point Lee has already made this morning that Marathon’s onshore U.S. business is developing material growth for the Company, driven by material positions in three high-value liquids rich resource basins including the Eagle Ford, Bakken and Oklahoma Woodford plays.
Over the past two years the 2P resource base for these three assets through dedicated efforts to improve stimulation performance and testing infill spacing density to improve the recovery of the initial volumes in place. With this tremendous growth in the resource base, we are accelerating rig activity in the Eagle Ford and Bakken by 20% each and by 100% in the Oklahoma Woodford.
Accelerating the development activity brings forward the compelling value of these assets driving production growth in the U.S. onshore up to a 17% to 22% compound annual growth rate from 2012 to 2017. In 2014 we anticipate production of approximately 220,000 barrels of oil equivalent a day from the U.S. onshore assets rising to estimated production in excess of 300,000 barrels of oil equivalent a day in 2017.
Our top tier drilling efficiency and highly competitive well results in each area provide confidence to accelerate development activity broadly.
As we focus on increasing value in all three resource plays, the common vehicles to deliver the value include driving well performance, improving cost efficiency on expense and capital and continued resource growth through infill density and the inclusion of additional horizons for co-development. Recent increase in the resource base of our liquids-rich growth assets has moved U.S. onshore total net resource up to 4.5 billion barrels of oil equivalent as shown in the pie chart in the bottom right of the slide.
Of this 4.5 billion barrels of oil equivalent, 76% is from the resource plays in the unconventional assets of the Bakken, the Eagle Ford and Oklahoma. The previously mentioned increase in development activity for 2014 growth -- will include growth activity in rigs from 22 to 28 across the U.S. onshore asset base. Our legacy oil focused assets in North America including the Wyoming oil sands mining will provide strong free cash flow that supports this organic investment in our growth assets today.
On the following slides we will look more closely at the growth assets starting with the Eagle Ford. Over the eight quarters from Q1 in 2012 to the estimated end of Q4 ’13, sequential production growth in the Eagle Ford has been 620%. Alternately, annualized production to the estimated end of this year is more than 135% above 2012, truly compelling liquids-rich growth to be sure. We are anticipating an average of 90,000 barrels of oil equivalent a day in the third -- in the fourth quarter of this year for an estimated annualized 2013 production of approximately 81,000 barrels of oil equivalent a day.
Current production is approximately 95,000 barrels of oil equivalent a day, and we anticipate exceeding the 100,000 barrels of oil equivalent a day milestone before the end of December. With an acceleration of 20% in 2014, production is estimated to grow even further to approximately 115,000 barrels of oil equivalent a day for the full year and an annualized growth over 2013 in excess of 40%.
Production volumes in 2013 averaged 81% liquids year-to-date and a similar composition of production is anticipated next year. Importantly, our core acreage position is essentially held by production allowing us to focus the program on the highest value wells and affords the opportunity to further drive efficiencies and well performance through extensive patent development.
Looking more closely at the Eagle Ford well productivity, a combination of stimulation design and infill well density continues to improve individual well performance. In 2013 through year-end almost 90% of the wells we drilled are at or below 60 acre spacing. In the fourth quarter essentially all wells are between 40 and 60 acre spacing. And our wells drilled in 2011 and 2012 were essentially between 80 and 160 acres on average. The 2013 wells at the increased well density are yielding initial 30 day production and six month cumulative production in barrels of oil equivalent above and beyond the comparable wells drilled in 2011 and ’12 that were at significantly wider spacing.
Focusing on the plot in the bottom right of the slide, over the last two years we’ve essentially doubled the well density in developed areas, while simultaneously increasing early cumulative production by 34%. Similarly, the plot on the bottom left illustrates a 45% improvement, an initial 30 day producing rates over the same period from 2011 to 2013. A continuous focus and refinement of stimulation design drives the evidence to well performance. Stimulation design parameters continue to be systematically varied across the acreage and the hydrocarbon phases.
Pad development at closer lateral spacing provides the opportunity to positively impact the efficacy of stimulation treatment, effectively increasing our realized complexity and resulting in increased hydrocarbon recovery. I’m going to talk more about the recovery details in a few minutes. The improvements in well performance are effectively mitigating potential impacts from increasing well density and we will focus on this details that support this notion more closely in the following slides.
Prior to resuming operatorship for the first major acquisition in the Eagle Ford, we’d already begun progressing to strategy for pilot well testing spacing in the Eagle Ford. The first spacing pilots replaced on the production in the Q3 of 2012. As we end this year the early pilots have achieved 12 months of production and in addition we have many more spacing pilots with six to 12 months of production. This early focus on spacing pilot scale has positioned us to understand well performance at 40 to 60 acre spacing broadly across our acreage position. And by extension allows us to effectively develop on the highest value spacing.
And looking at recent well results from the second half of 2013 across our acreage, wells at 40 to 60 acre spacing in the high GOR oil and condensate areas are performing very well with initial production rates ranging from 1,400 to 2,300 barrels of oil equivalent a day with all wells shown on a 24 hour stabilized rate at a maximum of a 16/64 choke. Our most recent efforts have focused on improving the performance of the high GOR oil areas at 40 acre spacing and you can see from several of the wells groups that we have on the slide in the gray boxes that we’re having excellent success.
In the two specific area example plots shown in the top left and the bottom right of the slide, we see from high GOR wells completed earlier this year initial cumulative production improvements ranging from 19% to 23% when compared to similar wells from prior in 2012. As we have existing units partially developed on 60 acre spacing and high GOR oil, we are moving forward in Q1 of ’14 to start 30 acre spacing pilots for additional infill and resource recovery opportunities.
With the pilot data spread across the acreage position and the production data from the groups maturing, so the question is what exactly have we learned from these efforts and how does this truly impact our ultimate development in the Eagle Ford?
Starting with the high GOR oil areas, we have select areas moving forward with 40 acre development now and all high GOR oil acreage being developed at 60 acre spacing outside of these select areas. The early performance from wells using our newer stimulation treatments in only in the last three months are performing above even earlier expectations, providing further confident that material additional high GOR oil acreage will move into 40 acre development in the first half of 2014. Ultimately we anticipate our high GOR oil acreage to be developed at a combination of 40 and 60 acre spacing.
Focusing on the plot in the top left of the slide the recovery of a single well is illustrated relative to the base case 80 acre spacing shown on the far left of this plot. As the spacing is decreased in the single well to 60 and 40 acre equivalence the drainage area of the wells begin to compete for hydrocarbon molecules and the recovery of these wells relative to the 80 acre base case are reduced. The gray bar illustrates the range of actual results noted today.
At 40 acre spacing, we anticipate over large numbers of wells that the relative recovery of that 40 acre well will converge at approximately 80% to 85% of the ultimate recovery of an 80 acre high GOR oil well.
Moving to the plot on the bottom left the value of down spacing is further illustrated using a nominal well spacing unit. The base case on the left represents an 80 acre spacing unit where we would include three wells at 750 foot spacing. Increasing this density to 40 acres would double the well count to six and increases the unit by approximately the unit net present value by approximately 50% when compared to the 80 acre base case.
With the relative recovery per well at 40 acre spacing performing very well, we can see the increasing density from 80 down to 40 acre spacing is well supported with increasing net present value across the spacing unit. Importantly an individual 40 acre spaced high GOR oil well would have an estimated before income tax internal rate of return of 30% to more than 100% and would compete favorably for capital in our broader Marathon portfolio on a standalone basis to make sure we’re allocating capital properly.
Similarly we can focus on the gas condensate where we are developing all of our remaining acreage at 40 acre spacing and we have been developing at this spacing since the second quarter of this year. And the plot to the top left, similar to the previous slide, we can see it as we move from 80 acre to 40 acre spacing. We anticipate the recovery that a single well spaced at 40 acres relative to an 80 acre base case will recover approximately 85% of the ultimate recovery of that 80 acre well.
Focusing on the growth plot in the bottom left of the slide, we can see the gas condensate nominal spacing at 40 acres provides a net present value uplift of approximately 60% compared to the same 80 acre spacing unit. Driven by improved relative permeability increased reservoir pressure, the condensate wells yield higher initial production at similar producing conditions and offer modestly lower capital cost without the need for a beam pumping unit and hence our confidence in them.
An individual gas condensate well at 40 acre spacing will yield, before income tax internal rate of return of 50% to more than 100%, readily attracting capital on a standalone basis across the broader portfolio, effectively establishing a wide area of development of gas condensate at 40 acre spacing and high GOR oil acreage at 40 and 60 acreage spacing, how does this development translate into our ultimate anticipated resource capture.
Taking the well improvements, and early pilot results into account, and reiterating what Lee has already demonstrated this morning, we find the 2P resources have more than doubled in the two year since the initial acquisition in the Eagle Ford from 469 million barrels of oil equivalent to 1 billion barrels of oil equivalent, that’s a long way to move in two years. We effectively acquired the initial volumes and through improving the well results and demonstrating the value of the increased density, we capture the upside value and resource. This resource corresponds with an Eagle Ford well inventory of 2,300 net wells, or 3,300 gross wells.
Where just over half of these wells are high GOR oil, another quarter of gas condensate with the remainder in our lower GOR oil areas, through additional infill of the 60 acre oil areas, increased recovery with stimulation efficacy and additional horizons for co-development that I’ll detail in a moment, a total net resource of 1.5 billion barrels of oil equivalent is established.
With significant resource growth and best-in-class drilling efficiency, we are accelerating the value of the Eagle Ford asset base by increasing the well development from 290 to 350 gross operated wells in 2014. This is an increase of 20% of wells drilled relative to 2013 efforts, utilizing initially 18 rigs.
But the increase in wells to sales production growth will improve to a 30% to 35% compound annual growth rate over the 2012 to 2017 period. The acceleration will increase the forecast field peak rate to approximately 150,000 barrels of oil equivalent a day in 2017. The growth will leverage our extensive existing central batteries and pipeline network which currently includes 70% of our oil in pipe with the liquids effectively accessing the premium Louisiana light market for value enhancement.
As we continue to pursue further down spacing, well performance improvements and other horizons, we can use these additional volumes to extend the peak field life at our discretion.
Having established a significant resource base, growing production and value, let us turn to consider more widely how Marathon wells perform across the large area we are developing. And looking at the map on Slide 38 we’re focusing on extensive area across six counties that include the majority of our acreage with 304 of Marathon wells and over 870 outside operated wells, all with a minimum of six months production.
Starting with the oil wells represented by the green spots on the map, we group the wells by cumulative production on a barrel of oil equivalent basis and we separate them into four quartiles. The bar plot in the top left is ranked by operator with the highest percentage of wells in the first, and second quartiles on the left side of the plot.
Within this group Marathon wells are consistently high performing across a large sample of wells spread across the entire area. Importantly, we have very few wells in the bottom quartile consistently delivering strong well results.
Also as we are not on the far left of this plot, we still have room to improve. We’ll look closely at the ideas of ours to continue that journey. Similarly in the bottom left, the condensate area, our wells are also high performing across a large sample with very few low performing wells, second only to a single operator in this example who has a much smaller focus area.
Having established competitive relative to peers, let us turn to focus on Slide 39 on our operational efficiency and beyond well performance the other significant opportunity to improve value is through capital efficiency. Over the past two years we have and continue to focus in decreasing our cycle time performance to improve cost efficiency and then simply bringing the wells to sales faster.
We are currently at a 12 base spud to TD cycle across our activity and we anticipate further improvement in 2014. The plot on the bottom right depicts this data clearly. As we use public data to evaluate our efficiency, we find in the plot in the top right of the slide that Marathon is simply the most efficient driller across the nine counties in which we operate. We average a daily drill rate that’s 40% higher than the average well in the nine counties and faster than any single peer.
Looking forward into 2014, we anticipate this efficiency will drive our well cost down further to $6.5 million to $7.5 million compared to our 2013 year-to-date average cost of $7.8 million even as we improve well performance further.
In addition to capital efficiency we’re focused extensively on keeping our wells and our facilities running effectively. Year-to-date 2013 our operational availability in South Texas has averaged 97%, maintaining the high reliability in our wells and facilities is critical to sustaining production growth. There are incremental volumes from high reliability or very high margin and they drive down our unit expense costs.
And looking at the operational availability chart in the bottom left of the slide, you can see that we acquired our initial acreage in late Q4 of 2011 and closed another significant acquisition in Q3 of 2012. After each of these acquisitions the operational availability improved within one to two quarters after our purchase effectively demonstrating that we can purchase asset and operate them more efficiently than the peers from which they were purchased. Focusing on reliability and maintenance now prepares us to maintain our strong production base overtime.
Beyond the Eagle Ford primary horizon we’ve started to test the opportunity to co-develop the lower Austin Chalk and Upper Eagle Ford directly with our primary lower Eagle Ford development. It is important to note that as we are testing the Austin Chalk interval it’s very different than the analog peer SOL and getting fields that many of you are familiar with. Our initial evaluation and results suggest the opportunity is clearly not your father’s Austin Chalk this is a question we get often and the Austin Chalk in our core area is in direct, is unique and different than those analog fields whereas in direct contact with the Eagle Ford source reservoir, it contains total organic content indicating partial self sourcing of the hydrocarbon in place.
The Austin Chalk is fractured more than the Eagle Ford, but at lower intensity than the analog fields and early indication suggest that no conventional trap maybe needed to retain this hydrocarbon in the reservoir. We’ve recently installed two lower Austin Chalk Upper Eagle Ford pilots similar to the diagram in the upper right of the slide. We are testing the Austin Chalk and Upper Eagle Ford directly over lower Eagle Ford wells to see the performance of all the wells in the system as a co-development. One older well the Weston 118-1H’s cumulative production in excess of 470,000 -- million barrels of oil equivalent since February of 2010 confirming the wells will produce for an extended period of time.
In the plot on the lower right combining the Austin Chalk Upper Eagle Ford wells into a time normalized composite at the 90 day interval well performance from this 4,000 foot length of group of wells is very similar to an Eagle Ford condensate wells in the area of the same length.
Importantly, confirming the performance of the combined reservoir system. Early results of the wells also indicate that Eagle Ford wells underneath are performing as expected and similar to area offsets, a key aspect of testing this system together. Suggesting these two intervals, are in fact draining separate volumes of a continuous hydrocarbon column. As we drill longer laterals and continue to improve the stimulation design for the Upper Eagle Ford Austin Chalk combination we anticipate further improvements. We can leverage the existing extensive infrastructure with co-development and we’ll be delineating the productivity of these upper horizons more widely in the first half of 2014.
Turning the focus on the Bakken, production growth over the last eight quarters has increased by more than 150%. On an annualized basis, estimated 2013 production will average almost 39,000 barrels of oil equivalent a day, an increase of more than 30% compared to 2012. Fourth quarter 2013 is estimated to average approximately 40,000 barrels of oil equivalent a day. As we look forward into 2014, we anticipate an average of approximately 46,000 barrels of oil equivalent a day, an annualized increase of 20% over 2013. These volumes are 94% oil focused and the growth is a combination of new development wells and recompletions that I will address in subsequent slides. Bakken is a compelling low risk asset that continues to improve every year.
In fact improving the well results every year is a hallmark of our Bakken asset. Starting with the plot in the bottom left over the last five years initial 180 day cumulative oil production per well has increased by more than 300%. And over the same period estimated ultimate recovery per well has increased by 50%. Stimulation design improvements continue to evolve with specific designs for each area and reservoir driving further growth in value.
Our current best practice 30-stage design started early in 2013, and year-to-date they have increased initial 30 day productivity by 19% compared to 30-stage wells in 2012 and earlier.
Turning to the plot on the bottom right, and looking at specific stimulation design progression, we can illustrate that the improvement in initial oil production has been 122% moving from the earlier open-hole designs to our current 30-stage best practice designs. Bakken improves well performance every year and certainly 2013 is no exception.
Turning to Slide 43, we focus on 2013 results, moving from our initial 30-stage stimulations to our current enhanced 30-stage best practice design. The current best practice includes a host of unique improvements including profit loading, fluid systems and increased profit volumes. Focusing on the four bar plots spread around the perimeter of the slide, the darker blue bar illustrates 2012 30-stage completed wells with the older design, and the lighter blue bar illustrates our current best practice well designs the 30-stage.
And across the acreage position, in both the middle Bakken and the first bench of the Three Forks we can demonstrate initial 90 day cumulative production increases ranging from 8% to 34% with our new design. Over the basket of 2013 total wells stimulated the average well has improved by 25% using the new 30-stage design.
Focusing on the gray boxes on the map, we report initial 24 hour production rates from several recent wells including the two highest initial producing wells we’ve developed to-date and in fact we look more broadly, 15 of the 20 best wells we’ve ever placed on production in the Bakken have come in 2013 with this new design, clearly driving production value and growth, importantly the increased stimulation efficacy demonstrated this year leads us to additional improvements we can test further in 2014.
Our well results provide high value and they continue to improve each year as we zoom out and focus not only on our own wells, but all the wells in the large area. We find the Marathon Bakken wells are consistently high performing relative to peer-operated wells. And looking at the map being evaluated in the area, well over 430 square miles in which the reservoir quality was estimated to be similar across the middle Bakken and the Three Forks first bench.
We included wells from 2011 to current date with at least six months cumulative production to focus on the more current high stage stimulations employed in the Bakken. The bar plot is organized to illustrate the operator with the highest number of wells in the first and second quartile based on cumulative production on the left-hand side of the plot. In this broad comparison, Marathon Bakken wells compete very favorably, a high percentage of the wells in the upper quartiles and again very few core performing wells.
Similarly, we can illustrate across our Bakken activity that Marathon is delivering an undisputed best-in-class drilling efficiency across all of North Dakota. Utilizing public data, the plot in the top right illustrates Marathon drills wells faster than any other operator and 78% faster than the average peer. As the bar plot in the bottom illustrates and as Lee mentioned earlier, this drilling efficiency has resulted in an impressive 32% improvement in an already mature basin and our spud to TD cycle time continues to come down every year.
These and other capital efficiency improvements allow us to further reduce our estimated well cost for 2014 to a completed well cost range of $7 million to $7.8 million down from our year-to-date 2013 cost of approximately $7.6 million.
Turning to expense efficiency, our focus on operational excellence has led to a 96% operational availability of our wells and facilities year-to-date 2013. With limited production lapses, we continue to capture the high margin barrels and again drive down our unit costs.
In the fourth quarter of this year our first infill spacing pilots in the Bakken commenced production. These new pilots are illustrated on the map on Slide 46 by the gray squares. Initial 24 hour production rates from these 320 acre space wells range from 1,200 to 2,800 barrels of oil equivalent per day, within the range of initial production from similar linked wells at wider spacing in the same areas.
The 320 acre pilots are in our core acreage areas, and they consist of four middle Bakken and four Three Forks first bench wells. As we evaluate the results of these important density pilots, we’re also participating in two deeper Three Forks pilot tests today and we start our own operated deeper Three Forks pilot testing in the first half of 2014 as illustrated by the orange dots on the map. Demonstrating viability of co-development opportunities in these vertically stacked horizons provide additional pad drilling and completion efficiencies and will further enhance our resource growth in North Dakota.
Another opportunity to increase production and resource is effectively recompleting older wells that were initially completed with well designs, now in consistent with current best practice. We have approximately 100 older wells with open-hole single-stage completion. In 2009 we successfully recompleted nine wells with an initial estimated increase in recovery of 280,000 barrels of oil equivalent per well.
In 2014 we anticipate dedicating one rig full time to recompletions and we’ll finish approximately 20 to 24 recompletions, utilizing our current best practice 30-stage designs and guided by the knowledge gained in the initial recompletions of 2011, we anticipate results at or above the results from two years ago. And in fact our first recompleted well was placed on the production in the last week and the initial results are very encouraging.
As we move across the acreage further developing units with existing older wells, we will recomplete the older wells as we drill and complete the additional new wells from the same pad to maximize efficiency of the entire pad.
The significant improvements in Bakken well productivity over the past two years with our efforts to further understand the opportunity for co-development, the Middle Bakken, the Three Forks and additional horizons our 2P resource base has grown more than 80% in the last two years from 345 million barrels of oil equivalent to 630 million barrels of oil equivalent. Over this same time our net well inventory has grown from 450 to 1,300 wells. As we continue to investigate the deeper Three Forks benches opportunity for additional higher density development and improved stimulation performance each year our total net resource can capture as much as 740 million barrels of oil equivalent in the Bakken.
Turning to Slide 49, we’ve established continuously improving well results in the Bakken and coupled with our already low cost falling further we are moving the needle on value for the Company. As a result of the improved well performance and through infill density our resource base also continues to grow to accelerate the value of this growing resource and with the confidence in our execution and focus we will increase our development activity by 20% to six rigs throughout 2014.
The increase in activity will drive our compound annual growth rate to 14% to 18% over the 2012 to 2017 horizon. This will drive our estimated 2017 production up to approximately 65,000 barrels of oil equivalent per day as we monitor the performance of the infill spacing pilots, the deeper Three Forks pilots and the recompletion efforts encouraging results from any one of these efforts may lead us to consider additional activity increases in the Bakken.
Turning to Slide 50 and our focus to Oklahoma, we find three liquids-rich resource plays, the third of our liquids-rich resource plays we continue to expand our activity and our position in the Oklahoma Woodford through additional leasing, acreage acquisitions and identifying additional zones of interest. We currently hold 180,000 net acres across the Anadarko Basin and 40% of this acreage has been identified with vertically stacked opportunities for development.
This acreage provides a total net resource of almost 1.2 billion barrels of oil equivalent. We’ve been focused throughout 2013 in the South Central Oklahoma Oil Province, also known as SCOOP, growing our acreage in this specific area by 21% at low cost. As we participate widely in Woodford development activity, we own interest in over one-third of all wells, all Woodford wells drilled today, including participating in nine infill spacing pilots to understand the opportunity for spacing in this critical liquids-rich resource.
Looking more closely at our SCOOP activity in 2013 where we had nearly all of our operated activity. We can demonstrate clearly that SCOOP well performance is simply breaking out over our performance in 2012. To become more active in the Woodford trend, we have consistently indicated a need for a combination of improved costs and resource growth to drive value. As the plot on the bottom left illustrates the desired well performance has truly arrived our single section one square mile wells with approximately 5,000 foot laterals have improved by more than 20% this year in 30 day rates.
More importantly as we have extended our laterals materially in the larger spacing units, this group of wells with longer laterals has improved by more than 130% compared to 2012 wells and initial production.
Shifting to the plot on the bottom right, the average 2013 well with six months of production is outperforming our wells from two years ago by almost 160%. The improvements in well performance have been positively impacted by focusing on high value acreage, landing the wells in discrete intervals, increasing stimulation stages, moving to longer laterals in larger units and by modifying our flow back process.
Turning to the map, we illustrate several recent 2013 SCOOP wells with initial 30 day production ranging from 1,027 to 2,500 barrels of oil equivalent a day, these are 30 day averages. With the liquids produced -- with the total production having 53% to 62% as liquids fraction. Marathon’s efforts have extended the SCOOP play further to the south and the west than any other operator as evidenced by the Davenport Ranch 1-28 well on the map. This well is not only a play extension but it’s a single best well we’ve developed in the SCOOP to-date.
After our improved well performance the other opportunity we needed to deliver increased activity in the Woodford, it has been improved cost efficiency. As we focused in the SCOOP area, we have materially improved our execution focus. The plot in the bottom right illustrates that our spud to TD cycle time has decreased by 37% over the past two years.
Moving up to the plot on the top right, we can use public data similarly to the other two resource basins to illustrate our drilling efficiency measured in feet per day and we find that we compare favorably with other peer SCOOP activity and while we were not yet best-in-class in drilling efficiency in the Woodford we anticipate challenging for this position as we have in the Eagle Ford and the Bakken in the past two years.
Importantly, and looking at operational availability, the Mid Continent team based in Oklahoma City has delivered 99.6% operational availability year-to-date 2013. This is in fact the highest single reliability of any asset across the Company this year. Keeping our wells online drives margins, drives down expenses. And they are clearly focused on that in Oklahoma today.
Over the past two years, we’ve undertaken a substantial effort to refine our understanding of the Oklahoma resource potential. This evaluation effort combined with the results of our ongoing Woodford development and in particular the improving well results of combined to more than double our estimated 2P net resource from 300 million barrels of oil equivalent to almost 800 million barrels of oil equivalent over the past two years.
Our net well inventory has similarly grown from 530 to just under a 1,000 wells. As we continue to evaluate infill space and drive well performance and evaluate additional vertically stacked horizons, we see an opportunity for total net resource at 1.2 billion barrels of oil equivalent.
Our Oklahoma resource base has risen dramatically in the last two years. On acreage we largely already own an often hold through production. Our well performance has improved materially and the well costs are improving. We’ve demonstrated the markers we saw and have them in hand and as a result our confidence has grown and we will accelerate our Woodford development by 100% in 2014 from two to four operated rigs. The change in activity increases our compound annual growth rate over the 2012 to 2017 period to between 30% and 40%.
2014 Woodford only production is estimated to average approximately 15,000 barrels of oil equivalent a day. And in 2017 the Woodford unconventional resource will reach approximately 35,000 barrels of oil equivalent a day, contributing material to the overall U.S. onshore growth rate, more importantly individual well return metric for the Woodford wells have improved and with modest additional improvement this area where we hold a large resource would compete favorably for additional capital and activity in future years.
Moving beyond the Woodford in Oklahoma, we started testing horizons in the Southern Mississippi trend and the Granite Wash. Opportunities we’ve identified and begun the test in the Southern Miss trend are liquids-rich oil and condensate focused and they have low water production. While they are Mississippian in age these opportunities are distinct from the higher water producing Mississippi Lime, much further north in Oklahoma in Kansas.
We have two early wells drilled, with one completed and early results are very encouraging. We are at present drilling the first of two Granite Wash wells, and a redevelopment of an older field that has vertical wells in it. These newly identified targets combined with a robust Woodford program to offer clear future upside in our Oklahoma liquids-rich resource base.
In summary, in the U.S. onshore business we’ve successfully grown our resource base by more than 100% in only the last two years. With this incremental resource, we’re accelerating activity in the Eagle Ford and Bakken by 20% and the Woodford by more than 100%. The increase in activity to 28 total rigs will result in a U. S. onshore compound annual growth rate of 17% to 22% over the 2012 to ’17 period with the resource plays growing greater than 25% across the same period.
Marathon has demonstrated best-in-class drilling efficiency across Bakken and Eagle Ford and competing for a similar position in Oklahoma. We are focused on operational excellence widely and driving to improve well results is our constant focus.
Thank you for your time today and note that an updated individual type well metrics for all resource plays are included in the appendix on Slide 102, but don’t go there now, because I’d would like to introduce my colleague Mitch Little, Vice President of International & Offshore who will conduct you through the next section. Thank you.
Good morning, it’s great to be here and to have this opportunity to share some of the highlights of our international and offshore production operations with you, while there are many synergies between our offshore Gulf of Mexico operations and our international portfolio. I’ll focus my comments today on our international business, and ask you to refer to the appendix for an overview of our Gulf of Mexico operations.
Production contributions from individual assets are shown on the map on the right half of the slide. Our international operations contributed 51% of the Company’s production volumes and 67% of the Company’s segment income through the first three quarters. As also shown on the map, our international volumes are highly concentrated within three company-operated assets, two of which are located within the North Sea, along with our integrated gas business in Equatorial Guinea. Collectively, these operated assets contribute approximately 80% of our 2013 international production.
Our international portfolio which has sourced significant free cash flow over the past few years helping fund Company growth into emerging plays in the U.S. will continue to be a high value contributor for many years to come. With the four year outlook showing 2000 production levels marginally higher than the estimated 2014 volumes.
Note that the 2014 and forward volumes exclude Angola, but maintain projections for North Sea assets currently being marketed. The portfolio’s advantage from being liquids-weighted, Brent-based and maintains material upside potential which has been targeted through applied technology and further near-field exploration, both of which I’ll come to you over the next few slides.
I’d like to review the performance and near-term activities of our two most significant international assets in a bit more detail starting here with what has been the Company’s largest producing asset over the past few years, Equatorial Guinea. Based on a proven track-record of delivering outstanding reliability and safety performance and its large reserve base, this asset continues to represent a stable foundation within the international portfolio.
It has been and continues to be a source of significant free cash flow. And as shown on the embedded production chart will remain a significant producer for many years to come. A major contributor to the near-term production profile is delivery of the Alba B3 offshore compression project which I’ll discuss in a bit more detail on the next slide.
Notably our EG license portfolio has recently been expanded with the acquisition of a new exploration license which we acquired in 2012. Multiple prospects spanning across the newly acquired block, as well as previously acquired licenses represents an exciting opportunity for material, liquids-prone upside towards the end of this decade.
We’re gearing up for a two-well program starting near the middle of 2014 subject to rig arrival date. I’ll share more details about that exploration opportunity in just a moment, but I’d like to start with a quick update on the Alba B3 compression project. This category one major project based on its relative scale and complexity is being executed by our global developments team, leveraging their extensive international project delivery experience and a proprietary stage gate project management system that was redesigned to capture best industry practices and implemented in 2012.
The majority of the project scope has been awarded to Heerema Fabrication Group and includes installation of a four-legged fixed jacket platform with top sides totaling approximately 5,800 metric tonnes, as well as 70,000 horsepower of turbo driven centrifugal compression, which has been designed with full redundancy to ensure preservation of our world-class reliability.
Additional scope within the project includes installation of new power generation, along with all necessary inter-field connections and associated process control and safety systems. The major facility components will be installed in the field during a single heavy-lift campaign, between Q4 2015 and early second quarter of 2016. And following tie-ins and commissioning, the facilities are expected to be in service by mid-2016.
The project notably allows reservoir abandonment pressure to be reduced by over a 1,000 PSI, developing significant incremental reserves while extending field life by approximately six years. The project remains on-track for completion within original schedule and cost targets.
Let me turn now to the newest addition to our Equatorial Guinea portfolio. This near field exploration opportunity has the potential to significantly enhance an already solid integrated gas business while shifting the product mix towards higher liquid content.
In 2012 we were awarded Block A12, which as shown on the map in the lower left section of the slide is immediately adjoining into the northwest of our existing operations at Alba field. This acreage combined with the adjoining sub-area B represents a material collection of more than 10 near field relatively low geologic risk oil-prone exploration prospects. Un-risked growth potential is in excess of 500 million barrels of oil equivalent and Marathon maintains a high working interest across both blocks.
Last week we executed a rig supply agreement to support this near field exploration program, as well as a development well within Alba field which will be the first development well since 2005. The rig is expected to arrive in the mid-2014 and the contract provides optionality to drill up to three wells.
In addition to the development well I just mentioned, we plan to drill two high quality prospects, the Sodalita West prospect in Block A12, along with the Rodo prospect in Sub Area B. The 2014 exploration program is targeting a combined 100 million Boes of mean un-risked resource and has an estimated chance of finding hydrocarbons in excess of 50% as both prospects are supported by 3D seismic derived amplitudes with AVO response as highlighted on map in the lower right portion of the slide.
Both prospects are also de-risked by adjacent discoveries each with confirmed oil presence. One of those discoveries, the Savarita 1A well on the eastern edge of our Sodalita West prospect produced 1,800 barrels of oils per day on drill stem test. We’ve applied recent seismic reprocessing and basing modeling which has led to an improved understanding of the subsurface theology, the sand depositional fairways as well, which suggests sand thickening at the proposed locations.
Additionally, regional studies of hydrocarbon source and migration pathways which are illustrated on the chart at the upper left portion of the slide suggest that the depth and burial history of the Akata formation source rocks have a higher probability of oil sourcing in this area. This is also supported by a number of nearby oil discoveries, including the analog Ebok and Ukvac fields in Nigeria as well as the TICO Marine and Victoria A. Moody oil fields producing just across the international border with Cameroon. This is truly an exciting new page in our EG storybook and I will look forward to providing further updates towards the latter half of 2014.
I’ll shift now to provide an update on the performance and future potential of our Norwegian-based assets. The story here has I think most of you would be familiar is one of an asset that continues to outperform expectations. Marathon sanctioned the Alvheim project based on an expected recovery of approximately 140 million Boes net and at the beginning of this year, 4.5 years after first production. We’ve produced essentially right at the original sanctioned recovery estimates, while projecting that more than 150 million barrels of oil equivalent remain to be produced.
Said another way, at the beginning of this year, total resources were more than double the original sanctioned estimate. We had more resources left to produce than we originally thought we had. And notably production levels have exceeded expectations by an average of 16% over the past three years. The performance has been driven in large part due to near field exploration success and advanced reservoir imaging and characterization techniques, coupled with extended drilling capability and technology application. These factors coupled with world-class operational performance and reservoir conformance at the high-end of our expectations continues to influence our future outlook as well.
Despite our announcement this morning of plans to market our North Sea assets, the graph in the upper right hand section of the slide demonstrates that the opportunity hopper continues to be refilled by our Norway team. And several additional opportunities are actively being pursued.
One of our recent near field exploration successes, the Boyla field which was discovered in 2009 and was formerly referred to as Marihuana is currently being developed as the fourth sub-sea tieback to the Alvheim FPSO.
Also classified as a category one project, it’s being executed following the same project assurance framework as the Alba B3 compression project, which I previously mentioned. The project is utilizing proven technology and extensive Marathon knowledge that’s been developed during the design and installation of the Alvheim and Volund fields and will significantly leverage existing Alvheim infrastructure. Sub-sea infrastructure fabrication is well underway and drilling will commence in the first quarter of 2014 while the sub-sea installation and commissioning program will be implemented throughout 2014.
First production is expected in early 2015. And in summary, the project is on budget and on-track to meet execution milestones and durations. In addition to leveraging our existing infrastructure and knowledge base, our Norway team continues to develop and screen new opportunities, especially where advanced technology can be used to increase the resource base.
I will highlight two of the more significant opportunities here. Throughout much of the Alvheim area, the reservoirs consist of thin oil layers sandwiched between gas above and water below. Today, wells have been optimally placed to reduce gas encroachment into the wells in order to maximize oil recovery.
The placement of the wells and the physics of the fluid flow in the reservoir mean that attic oil above existing wells is largely left unrecovered. Working directly with our internal reservoir characterization experts, existing seismic data has undergone refined processing to better image the productive areas of the field. And earlier this year 4D seismic data was acquired to help us identify areas of the field that are not being adequately drained by the existing wells.
We’re working to combine these new reservoir insights with emerging completion technology, that’s showing good results in a similar application at the Troll Field in Norway. This advanced inflow control technology is currently being evaluated for use in portions of Alvheim, as well as the Volund field.
Application of the technology would allow wells to be placed closer to the overlying gas, as the devices preferentially allow oil to pass through while restricting gas flow. This would allow fractional recovery of some portion of approximately 100 million barrels of oil in place that is currently trapped above the existing wells.
Evolution of the technology will be complete in 2014, in time for potential inclusion in 2015 and beyond infill drilling programs. And similar to the near field exploration in Equatorial Guinea, advanced process of 3D seismic data in the Alvheim area has shed new light on some past non-commercial discoveries, including two wells that were drilled on the fringe of the Gekko prospect which lies to the south of Alvheim and immediately east of Volund field.
Results from the wells indicate a high probability of gas with a thin oil column. However, prospect volumes are potentially significant as the revised seismic interpretation shows that the previous wells were drilled at suboptimal locations.
Additionally, and unlike the situation we face in North America, gas still attracts significant value in the European market with a relatively stable oil to gas price ratio on the order of 10 to 1 versus an oil to gas price ratio in the U.S. currently on the order of about 24 to 1. The Alvheim partnership is currently evaluating whether to drill a follow-up appraisal well based on this improved subsurface imaging.
In summary, our international production base is highly concentrated within three Company-operated assets. And while they have differences in terms of product mix, geography, as well as facility-type and maturity, individually and collectively they share one very common trait, a commitment to operations excellence.
That commitment secures our license to operate and drives the behaviors aim to ensuring our people our assets and the environment are protected. Importantly, those same principles that have been engrained into our safe and responsible operating philosophy also translate into top-tier reliability performance with less than 2% unplanned losses across all of our Company-operated international assets in 2013.
This world-class operating performance represents a proven competitive advantage and one that is transferable to new opportunities within the offshore and international arena such as some of the areas that Annell will be discussing during her global exploration overview which is coming up next, thank you, Annell?
Thank you, Mitch and good morning. I’m here to tell you all about the successful start of our renewed exploration program at Marathon. Many of you have heard about our new portfolio for exploration and your first question might be, so what’s different years past.
We are targeting material oil and material positions either in proven or emerging hydrocarbon provinces and basins. Just in the last few years, we targeted entry into three new material provinces where we have the geologic experience and expertise and the depositional systems and the rocks that we’re ere targeting. Coupled with applying state-of-the-art technologies, we can high-grade a greater number of prospects which should increase our overall chance of commercial success.
By drilling over eight growth impact potential wells per year, we have the opportunity to deliver sizable new resources to the Company. You have also heard us talked about and show, we have shown you our capabilities and our value as an operator. So, we want to continue that optionality that flexibility to decide, when to stay to operate and to develop or when to monetize our successes.
And as always we seek new opportunities with favorable fiscal terms and manageable above ground commercial risk, because ultimately, all exploration opportunities must compete on a risk basis to be able to deliver meaningful new value to the Company.
Using these guidelines, we have built a portfolio with significant oil potential. We’re in properties of over 20 million growth acres with a combined growth, un-risk resource potential range of about 4 billion to over 10 billion barrels of oil equivalent. The four areas are, the Gulf of Mexico, Subsalt Sandstones and the Jurassic and the Gabon Pre-salt sandstones and the Fractured Carbonates of the Kurdistan region of Iraq and the fluvial lacustrine sandstones in the onshore rift of Ethiopia and Kenya.
And 2013 has been a successful year on our renewed exploration program. Starting in the East in Kurdistan, we announced the Mirawa discovery on our operated Hirir block, and on the Atrush block we received approval for field development. In Gabon the Diaman-1B discovery in the pre-salt confirms our working petroleum system. Also in Gabon we recently announced high bidder on two additional deepwater blocks. And in the Gulf of Mexico we were in the successful appraisal well at Shenandoah, a Paleogene discovery. And Gunflint is progressing towards first oil by mid 2016.
It has been a successful and exciting restart year for us. We estimate the 2013 exploration drilling results to-date adding over 250 million barrels of oil equivalent net new resources to Marathon. And we have additional follow-on opportunities. I'd like to show you a brief overview of each area with the latest activity and then the plans for 2014.
Starting in the Kurdistan region of Iraq, this is a world-class petroleum province that we entered in 2010 in four blocks and in three years we have three discoveries on three blocks. For the non-operated Atrush discovery in the second quarter, we received approval for the field development plan and in October entered the development period expecting first oil in 2015.
On the non-operated Sarsang block we have the Swara Tika discovery in the Triassic and we have drilled one appraisal well.
And in the Marathon operated Hirir block we announced the Mirawa discovery with flow rates of over 11,000 barrels of oil per day from the Jurassic and over 72 million cubic feet of gas and 1,700 barrels of condensate per day from the Triassic.
In November we filed the notice of discovery with the ministry and on the Hirir block we have entered the second sub-exploration period giving us an additional two years. Next we will drill on analog structure to Mirawa called the Jisik well. It will start in a few weeks. And after Jisik we expect to drill a Mirawa appraisal well, where we plan to also evaluate the Cretaceous potential. Once we see the results from those wells, we will determine the best plan for development.
Moving south, Marathon entered the East Africa rift play in 2012, in three blocks located in Ethiopia and in Kenya, based on the scale and scope of the opportunity areas within the rift play and with the recent analog discoveries as well as past discoveries. There could be significant remaining resource in the entire rift region, estimated at over 15 billion barrels of oil potential. That’s the remaining yet to find.
These are very large multi-million acre blocks with several independent sub-basins on each block, containing numerous prospects and leads with an each sub-basin. In the initial phase we are gathering new FTG -- full tensor gravity gradiometry data, which is superior for delivering higher resolution and imaging the basin configuration than from traditional gravity survey. This is an emerging onshore opportunity it's onshore so it's lower drilling cost area applying newly acquired technologies to identify potential source areas and structures previously unseen.
In Ethiopia, we drilled the first two wells ever drilled in the South Omo basin, the Sabisa well and Tultule well, where we encountered good quality reservoirs which shows. While we will continue to evaluate and incorporate those well results, we plan to move to the eastern half of the block as you can see on the map to drill three wells next year in testing multiple sub-basins.
In Kenya on Block 9, we drilled a Bahasi structure and we did not encounter commercial hydrocarbons. In 2014 we will drill the solid structure on the eastern side of Block 9, for wells previously drilled in that sub-basin has confirmed a working petroleum system. It is still early days for the opportunities we have in East Africa rift play.
In the first three wells we drilled across the play we found the elements needed for success, and as we gain more data concurrently across these sub-basins, we could compare, rank and prioritize the optimum perspective areas. We think Block 12A in Kenya is another very perspective block, which is located along trend and to the south of the recently announced discoveries.
We are in this critical data gathering and integration phase, first we acquired full tensor gravity gradiometry over the entire sub-basin, and then selectivity acquired seismic data. In 2014 we will integrate these data and further evaluate where to target the first wells to be drilled on that block.
Moving over to West Africa, there is an estimated growth resource potential of over 12 billion barrels of oil equivalent in the entire deepwater pre-salt play in Gabon. The deepwater portion of the pre-salt is an emerging hydrocarbon province where onshore and in the shallow waters of Gabon over 2 billion barrels of oil equivalent have been previously discovered in the pre-salt section.
As mentioned the Diaman-1B discovery is the first well to be drilled in the pre-salt deepwater of Gabon, the well encountered over 160 feet of net pay in good quality stacked reservoirs. This well confirms a working petroleum system and the preliminary analysis is gas with condensate. You can see on the inset map that there are at least seven additional opportunities on the Diaba block, which is over 2 million gross acres. Some of these opportunities are adjacent to potential oil-prone source basins. The partnership is still evaluating the results of the Diaman-1B well and when completed we will select the next well to be drilled on the block in 2015.
We have a previous history in Gabon. Marathon was an operator for 17 years. We’ve done much sub-surface work in the pre-salt evaluating farm-in opportunities and selecting the Diaba block and building on to that work we participated in the recent bid round in October, where we were pleased to be named the high bidder and operator on two additional deepwater blocks with pre-salt potential. These blocks are still subject to successful contract negotiations and with that success we will be pleased to return to Gabon again as an operator.
And now the Gulf of Mexico, where we’re currently drilling our Marathon operated Madagascar prospect. This is a Jurassic Norphlet test in the eastern part of the Gulf of Mexico where successes were recently announced along trend to the north. These are high quality sandstone reservoirs and for the Madagascar prospect trapped in a four-way deep closure that is well defined on seismic data with the gross resource potential range of 100 million to 250 million barrels of oil equivalent. Currently we are drilling ahead at 21,600 feet expecting to reach a total depth of 25,000 feet before the end of December.
Looking forward in the Gulf, our largest portfolio of prospects is in the Paleogene play or sometimes called the lower tertiary. To-date billions of barrels of oil resources have been discovered in the Paleogene with the average field size estimated at 300 million barrels oil equivalent recoverable. We participated in the successful Shenandoah discovery first drilled in 2009 and in the appraisal well drilled this year encountering over 1,000 feet of high quality net pay. There have been over 10 commercial discoveries in this play with several more in predevelopment and thus ongoing plans for continued build-out of deepwater infrastructure.
We have technically high graded eight Paleogene prospects in our portfolio through state-of-the-art seismic imaging. These eight prospects are all located inboard beneath the massive Canopy of Salt. The Salt Canopy defines the inboard from the outboard. We plan to operate six of these prospects and currently with an average working interest of about 60%. There is opportunity for us to, either farm down interest or trade into other exploration projects and still target unmet material interest in each Paleogene prospect, and that may range between 35% to 50% depending on the opportunity.
In 2014, we expect to participate in another appraisal well at Shenandoah to fully assess the size of that discovery, as well as drill our first operated Paleogene prospect called Key Largo.
To give you more information on the play, the discoveries located inboard show superior reservoir quality to the outboard discoveries with inboard reservoir characteristics similar to the Miocene. The structures are large and the sandstones are thick and laterally expensive just like in the outboard. But the differentiators of the inboard are the high porosities and permeabilities that have been measured from recent wells, as well as better quality crude relative to some of the outboard discoveries.
The cross-section shown is a view of the Key Largo prospect target. This is a three-way trap against salt to be drilled to 34,800 feet in about 7,500 feet of water. We expect the new build rig from Maersk to be delivered next summer with the third quarter spud on the first rig spot. We have a three year contract on this new rig sharing at 50%.
Our success in 2013 has set the stage for our 2014 drilling program. We plan to drill at least eight new exploration wells next year that will continue to drive our exploration performance. One exploration well Jisik and Kurdistan, four exploration wells in the Ethiopia and Kenya rift play and three wells in the Gulf of Mexico, with emphasis on initiating the drilling of our Paleogene portfolio in the third quarter.
In summary, we have established a strong foundation to build onto offering balance between, risk, materiality, working interest and increase the annual number of drilling opportunities all needed for exploration to succeed. I am privileged to lead an outstanding exploration team in commerciality and commitment and creativity and they are the ones who have delivered the turnaround and success of the program today. I look forward to the well results this year at Madagascar and certainly those well results in 2014.
Thank you for your attention, and now, over to J.R. Sult, our Chief Financial Officer.
Good morning. Thank you, Annell. I am excited to be here today. As the newest member of the senior leadership team here at Marathon I am honored to be part of this group here. As you’ve heard from Lee and the operational VPs, it’s an exciting time to be here at Marathon Oil and I want to share with you today what we consider to be the core principles of our financial strategy.
This slide is a summary of that strategy, while the team has described how our disciplined approach to operations drives value, maintaining financial discipline is equally important to creating shareholder value. By that I mean, funding our capital allocation needs with our operating cash flow and portfolio management.
Our capital allocation process will be both disciplined and robust as we allocate capital to the highest return investment opportunities. Integral to that capital allocation process is rigorous portfolio management in which we continue to seek opportunities to optimize the portfolio to maximum shareholder value.
We’ll maintain a strong balance sheet ensuring our financial strength and flexibility to absorb market volatility, as well as to respond to growth opportunities. And we’ll continue to return capital to shareholders through competitive and sustainable dividends, as well as opportunistic share buybacks. Now we believe this strategy will maximize long-term value for our shareholders.
So over the next few slides I’ll expand on each one of these points. Both Lee and Lance have spoken to the reasons why we’re accelerating activity and capital spending in our high growth and high return North American resource plays in 2014. But what gives us the confidence to do that in a disciplined manner is the strength of our operating cash flows, which have been a hallmark of Marathon Oil for many years.
Our cash flows are highly leveraged to crude oil prices with more than 70% of our production coming in the form of high value liquids. Our total liquids realizations are the highest in our peer group for the first nine months of this year and about $95 per barrel. More importantly our estimated 2014 North American E&P segment operating cash flows have grown to represent about 70% of our total operating cash flows. The vast majority of that of course comes from our resource plays.
Said another way, nearly 60% of our total operating cash flows in 2014 were expected to come from those growing resource assets. And that piece of the pie of course will grow considerably with the successful sale of our North Sea assets as Lee highlighted earlier.
We continue to drive each of our North American resource plays towards positive free cash flow and we expect to achieve these milestones in 2015 for the Eagle Ford and Bakken and 2016 for Oklahoma Woodford, based on our accelerated 2014 activity levels. And however, we will continue optimize the development of these assets by balancing the benefits of positive free cash flow with the value that further acceleration could generate guided by our technical understanding of the resource size and the technology to develop it.
The bottom-line is that our operating cash flows together with proceeds from our portfolio management efforts will provide a substantial reinvestment capability in order to drive long-term sustained growth at competitive returns.
Now, before I leave the topic cash flows, I wanted to share with your just a snapshot of our after tax income and cash flow sensitivities to changes in commodity prices. And I am not going to read the entire chart to you, but the result is what you would expect from a large liquids-weighted portfolio for a $1 per barrel change in WTI yields about $60 million change in after-tax cash flows in 2014.
As the management teams were committed to being good stewards of our shareholders’ capital, so I want to shift gears to talk just for a moment about capital allocation priorities. As Lee highlighted earlier our first priority is organic reinvestment and while all incremental capital competes equally, our deep inventory of North America resource opportunities will attract more than 60% of our total 2014 capital program reflecting the high growth and high return nature of these opportunities.
Our next priority is to quality in material resource capture both by the bid, through our focused exploration program as Annell just described, and through opportunistic business development. Dividends are an important priority for capital, not only it’s a way to return value to shareholders but also as a form of reinvestment discipline. We want our dividend to be predictable, sustainable and competitive.
And as I said earlier, we work to maintain a strong and flexible balance sheet with sufficient liquidity to whether market volatility and to fund growth. And our final priority is to opportunist share repurchases, of course, this requires that excess capital be available but it provides us an opportunity for an additional return to capital to shareholders.
As this slide demonstrates we’ve had a long history of active portfolio management and this will continue to be an integral element of our capital allocation process. As we manage the portfolio for returns and value, there will be no sacred cows. And as I said, all assets in the portfolio will compete equally for capital.
Today’s announcement to market our UK and Norway assets demonstrates our focus on accelerating shareholder value by simplifying and concentrating the portfolio in order to focus on higher growth and higher return opportunity. As I mentioned a couple of times, our commitment to maintaining the strong balance sheet is stead fast. We have substantial liquidity both through cash on hand as well as through our committed revolving credit facility. And after completing our sales of Angola Block 31 and 32, our liquidity will increase by about $2 billion, $500 million of which will be used to repurchase shares.
Our financial strength is also evidenced by our credit ratings at both Moody’s and S&P and maintaining strong investment grade credit ratings is a requirement of all our capital allocation decisions. Now, we recognize that our balance sheet is a strategic asset provides us a great deal of financial flexibility and horsepower to drive growth and returns for our shareholders. And it’s vital that our shareholders have an equal seat at the table in the capital allocation process.
Returning capital to our shareholders is an integral element of our strategy and at Marathon Oil dividends will be the primary way we accomplish that. And since becoming an independent E&P Company we’ve grown our dividend by the compound annual growth rate by 10% and most recently raised our dividend in July of this year.
In addition to being predictable and sustainable, we also want our dividend to be competitive with a yield of about 2% we think it’s very competitive with our peers. And where excess capital is available opportunistic repurchases will be considered is a way to supplement our returns to shareholders. And since becoming an independent E&P, we’ve completed or announced $1.3 billion in share repurchases, with 500 million remaining to be completed with the sale of Angola Block 31.
And finally as Lee has highlighted, Marathon Oil Board has approved an increase in the remaining share repurchase authorization to 2.5 billion. This increased authorization provides us with financial optionality as we head into 2014. I hope you’ll agree that the financial strategy I’ve outlined is the right strategy to deliver Marathon Oil shareholders’ long-term value.
Thank you for your support and your interest. And I’ll now turn it back to Lee for a wrap-up and for Q&A.
Thank you, J.R. I will end our formal presentations today, really back where we started. In 2011, Marathon Oil became an independent E&P Company. In order to be recognized as the premier independent we must and we’ll excel in these seven areas. I trust that through today’s presentations, you have seen the tactical actions that support this strategy as we move into 2014 and have better clarity on the compelling investment case for Marathon Oil. I would also like to pause and recognize all of the dedicated Marathon Oil employees around the world that drive our results each and every day.
That concludes our formal presentations and we will now open for your questions. I would like to ask the other presenters to join me on stage and then we’ll begin the Q&A.
Arjun Murti - Goldman Sachs
Thanks Lee, it’s Arjun Murti with Goldman Sachs. Thanks for the update today. You’re shifting your strategy more towards U.S. shale with some decent growth expectations in higher CapEx. At the time there are some growing questions about the ability for the refining system in the U.S. to handle light sweet crude oil, those concerns may be premature in a near-term context but they probably are out there at some point, how have you thought about that and maybe how resilient are your plans to what could be much lower WTI oil prices, are these plane resilient at 80, 70, is there any kind of metric you can attach to that? Thank you.
We’ll certainly I think the point you are raising Arjun is one that’s well known in the industry today as U.S. shale production has continued to grow at really exceptional rates it has put pressure back on the refinery complex here in the U.S. as the shift to more sweet, light sweet crude has occurred. What I think has been quite remarkable is how adaptable the refining complex has been and being able to take on this different crude mix or different crude slate.
I think we certainly watch that, I believe there is still room. We’re still importing a considerable amount of crude here in the U.S. today. As we look out the longer term just has the discussion that has occurred on the gas side in the U.S., I think ultimately a discussion around how do we ensure that we’re not only getting our petroleum products but our crude into the world open market is going to be a question that will need to be addressed.
The rest assured that in the resource plays, the incremental well economics that Lance described are very robust across a very wide range of WTI and LOS pricing and we test those economics against those ranges to ensure that they’re robust. The other advantage of course that we have in the resource plays is that we do have scalable investments there. If we start seeing some stress around CapEx at the margins, we can take action, I mean a great example that has been the way that the U.S. has been able to respond to the moderation in gas prices in terms of rig count.
And I think you could see the same phenomenon if we saw more bearish pricing also on the liquid side as well. Thank you, Arjun, appreciate it, next question.
Ed Westlake - Credit Suisse
Thanks for the information on the resources in the Bakken and the Eagle Ford and the production guidance that you’ve given out to 2017. I may have got the math wrong but I looked at the resource life using 2017 production and it’s still over 20 years in the Eagle Ford and in the Bakken, so I mean, can you talk a little bit about what you plan beyond 2017 and may be talk a little bit to the constraints on going even faster in the short-term? That’s the first question. And then the second question is just very small, it’s on the stack and the SCOOP in the Woodford. I just don’t know how much acreage you have in each of those plays it would be helpful?
Okay yes thanks very much Ed. Well maybe I’ll start first with -- you are right Ed it all starts with our understanding of the resource base. And I think Lance very well laid out some of the excellent technical work that we’ve embarked on across all three of the resource plays which is driving an essence that well inventory.
The pace of development and the ultimate size of that resource, though it’s going to be a developing story as we learn more and more and as we do more some of the descriptions we’ve had around co-development for instance in the Eagle Ford around the Austin Chalk and the Upper and Lower Eagle Ford, very interesting but we’re still early days.
Similarly as we continue to test deeper benches in the Bakken, I think we’ll be revisiting our activity levels and ensuring that we are optimizing the rate life and the present value of those opportunities for the shareholder.
In terms of SCOOP and stack maybe I’ll say a couple of words and then turn it over maybe to Lance to offer a few comments there. One thing I will say and I hope it came out clearly in Lance’s talk is, the SCOOP incremental economics are really improving and they’re starting to approach some of the better incremental well economics that we’re seeing in the Bakken and the Eagle Ford. And as we learn more there, I think you’ll see us continue to evaluate our pace and optimization within the SCOOP.
He also mentioned of course that we’ve tested the, what we consider to be the southernmost extent of the SCOOP as well as we try to delineate really what is that resource going to be in the future. So the SCOOP to us looks very, very attractive and largely speaking, we were running two rigs this past year in 2013, we’re still very much in the early days. We benefit from a lot of held by production there and also as Lance mentioned we’ve been able to go out and do some acquisitions of addition leasehold there that will be very accretive to our SCOOP position at a very low cost basis.
The stack play which I know some of the competition is starting to use that term, Lance had mentioned that a large percentage of our acreage in the Woodford is stacked in nature. We’re looking at that in terms of the Southern Mississippi trend as Lance described it, it’s a very different trend than what people have seen further to the north in the Mississippi Lime have very some unique features.
And again we’re in the very early days but that could significantly impact the way we ultimately deplete and develop the Woodford area. Maybe I’ll just turn over to Lance maybe just to give a, maybe broad brush description of how our acreage position kind of distributes across those areas. Lance?
Well thank you Lee and you did a excellent job describing that. Addressing your first question, Ed, I think, it’s important to know we have the operational capability to expand further. We don’t have a near-term limit there. We’re deliberating choosing how much to accelerate and we’ll maintain some capacity for further growth should the economics and the opportunity warranted.
Focusing more specifically on the Oklahoma Woodford, we’re approximately 180,000 acres in the Anadarko Basin much of that is prospective for the Woodford. In the SCOOP sub-basin on the southern extent of that we have approximately 50,000 net acres prospective for high quality liquids-rich SCOOP and approximately 60,000 to 70,000 in the Cana Woodford for further north in the combination. And then a further subset of that, 40,000 to 50,000 acres of that same Cana Woodford is also prospective widely for the Mississippi -- Miss group in the southern -- some other have also referred to that as the stack play, again a Mississippian age a set of reservoirs that are overly the Woodford in that area and are generally Woodford sourced.
Thank you next question please.
Doug Leggate - Bank of America
Two questions if I may, so obviously you’ve described yourself as an independent E&P which of course you are now. You’ve also used this comment that you want to be the primary independent. So my question is, what metrics are you using to define that? And in answering the question, if I could ask to you address things like the change in mix as you give a Brent level production and bear in mind that a lot of your peers are drilling off a gassy basin, and therefore are seeing better I guess acceleration in cash flow. And I’ve got a follow-up to this?
Okay, sure. Well, first of all, I think, when you talk about metrics, for us the ultimate metric will be how we ultimately deliver return to the shareholder. The appreciation and direct divided. Of course when you look at that little much deeper I think you have to back to those seven strategic imperatives and as I look across those strategic imperative. That is how we’re going to judge our business performance. It’s that we recognize ourselves as premiere it’s when you recognize us as delivering premiere value and that’s what we have to achieve for. And my view is that if we deliver against those seven strategic imperatives, we will in fact then take the box for becoming that premiere moniker.
Your second question in terms of change in mix, if I can address that one, there is no doubt that our portfolio today benefits from having exposure to those WTI/LOS as well as to Brent pricing. I would say that’s an element that has proven to be very successful for us. I would also say that our European gas volumes of course give us some leverage as well as we’re able to put those through NVP and capture quite good returns there as well.
But again it’s a global marketplace, global supply and demand. I think the previous question we talked a little bit about commodity risk. We’re going to continue to allow our portfolio be driven by profitability not geography. And as folks -- I would hate for folks to walk away from this meeting thinking that our announcement to market means that we have less interest in the international space and exposure to Brent. What it says is that for today as we look at our portfolio that move makes sense for a verity of reasons and we’ve talked about some of those, the acceleration of cash flows in time that’s simplifying and concentrating our portfolio today into the higher margin U.S. resources plays and also giving a better line of sight on our overall growth brining our CAGR up from 5% to 7% to 8% to 10%, so a lot of very valid reasons for why we’re going to take that step.
But by no means does it signal that we still don’t want to have the capabilities and competencies that are going to allow our shareholders access to the full opportunity space, as you know the number one challenge for an E&P Company is access to new and material resource and as soon as we start limiting that playing field, that will be a disturbance to our shareholders. So, we’re going to keep that wide open from a risk management standpoint. You had a follow-up.
I thought I used that up. I thought that was one question, but thanks. I will follow up very quickly. Norway and the UK, you said 20% reduction in 2013, can you tell us what percentage of cash flow it is? Thank you.
I think it’s probably very close to that 70%, that 70% that I used on my chart was really looking at 2014 estimates of -- I'm sorry, it’s about 15% or so and okay if you look, go back to my chart that stack bar about 70% of that was North America cash flows, about 15% of that was UK and Norway cash flow, that’s probably in the right zip code for 2013 as well. Thank you Doug.
Blake Fernandez - Howard Weil
Hi it’s Blake Fernandez with Howard Weil if I could go back to Arjun’s question more specifically I was curious, I know in the past for Eagle Ford you’ve locked in contracts with the refiners at LOS minus 6 with WTI’s floor. And I’m curious if are able to contract future volumes at that same level? And I have a follow-up too please.
First of all, we’re not going to talk specifically about any contract terms, I think J.R. was very clear in his presentation that when you look our realizations, we’re able to establish ourselves very well commercially in terms of the realizations that we’re getting for our liquids product, our number one objective is to drive our barrels to the highest margin market that’s particularly important here in the U.S.. I think moving as Lance mentioned a lot of our South Texas volumes toward LOS has given us a distinct advantage, I think we’re going to continue to look at options to get our barrels on the water and secure the best realization that we can in South Texas.
Blake Fernandez - Howard Weil
And Lee the follow-up is and looking at Slide 22, your international presence, once you take UK and Norway out of the picture, I think it’s pretty clear Libya at some point may go and I think you’ve been clear that ultimately you may not develop Kurdistan, so you’re basically left with EG. I’m just curious if ultimately could you be out of the international game altogether?
Well certainly, I won’t get into the specific asset marketing decisions that we make internally, but maybe I’ll first talk through the couple of assets that you mentioned and maybe come back to the broader question of the international space. Libya currently of course we are just like everyone very interested in seeing peaceful resolution to the issues there in country. The one thing I would leave you with though and I hope it came through in some of my earlier remarks is that Libya is a very high quality subsurface asset.
It has a tremendous amount of growth potential there. It’s an asset that we think can deliver very strong volumes. In terms of ultimately how we capture shareholder value by argument will be that probably today is not the day to look to try to monetize that asset and capture maximized shareholder value. Longer term we’ll continue to test Libya just like all of our assets in terms of its overall fit for our portfolio, but in the fundamental metric of does it have a high quality resource, it certainly does.
Looking at Kurdistan, I think Annell did a great job describing our success there, we have the Mirawa 1 discovery well in our Hirir block and of course we’ve had very good success in the other two non-operated blocks as well. Atrush is moving has gotten the field development plan approval, it will see first oil in 2015, three wells 30,000 barrels growth a day.
So, we’re seeing good movement there in Kurdistan. The other thing in Kurdistan of course is the export routes that we’ll ultimately have access to and of course that’s gotten a lot of press recently around how those will ultimately progress, but in terms of securing value from the assets that we have on the ground there, I think we’ve created some optionality for the Company there, we can create value there possibly as a developer and operator, but at some point in time we might consider other monetization options to us as well. There is likely some consolidation that will ultimately go on in Kurdistan.
Back to the international point though again, I trusted as you heard the discussion of the exploration activity, we’re still very interested in those areas of the world from an exploration standpoint that can give us that quality and material resource. And as you look at those four areas that Annell described of course three of those four are still international in nature and we see those being very competitive with the other opportunities that we have in our portfolio.
The exploration team is not just out there looking at the rock quality that’s necessary but not sufficient for success. They’re also looking at above ground risk. They’re looking at the overall path to profitability to make sure that we understand if we have success how those assets are going to ultimately compete for capital allocation against U.S. resource plays and investment in Equatorial Guinea that Mitch outlined.
So again our portfolio is going to be very driven by profitability not geography, but we have go where we see those accretive opportunities and that’s what we’ve tried to layout today, thank you.
Paul Sankey - Deutsche Bank
Lee, on the Norway and UK where are you guys seeing that process and how confident are you that you can, I was wondering particularly about the Norway assets with the decline rate, how easy that’s actually going to be to Marathon? Thank you.
Well, we are very early in the process. We have just started that, Paul. We’ll beginning in earnest into marketing effort and our overall integrated approach to marketing early in 2014. We wanted to bring it forward because of course we’ve had the internal discussions, strategic discussions with our Board so the timing was correct to share that externally and get the process started. We think that the Norway assets that you specifically ask about are high quality assets. The team has done an excellent job of moderating decline overtime. As Mitch discussed, it really had outperformed all of our estimates. Additionally, the team has done an excellent job in country at defining the remaining potential that is there in Norway and Mitch described some of that.
We feel that the Norway asset will be very distinctive in the marketplace as we look at the type of assets that have come in for sale in the North Sea. We think Alvheim it’s very oily it’s still, it’s kind of in the midpoint of its lifecycle. It’s over performing high reliability, an outstanding operation almost on every metric. We think that will very much differentiate itself in the marketplace and we can’t speculate today on how successful. I mean, this is -- I will tell you this is not meant to be any type of prior sale. If we cannot achieve a full shareholder value for these assets, we’ll continue to operate them in a safer and responsible manner that we have been.
Paul Sankey - Deutsche Bank
Thanks. Now, when you were formulating this plan, what did you perceive to be the biggest risks or where did you struggle with most in terms of deciding the best way forward for Marathon? Because it’s obviously quite a significant inflexion point here, thank you.
Yes absolutely Paul. I think as I’ve said in my prepared remarks, we enter any consideration of marketing an asset, very, very thoughtfully. We have had extensive discussions with the leadership team as well as our Board on our approach and the value that we think it delivers. Whenever we enter in one of these, the biggest question that we have particularly when you are looking at one of these large areas where you have a very well established operating footprint is to ensure you really understand the potential upside and the remaining potential there.
We fight hard for these high quality resources and we work hard to develop these outstanding in a world-class operating team in these areas. And so when you take one of those decisions those are the key considerations that run through your mind is ensuring that you really understand that this is the appropriate next step. Thank you, Paul.
John Herrlin - Societe Generale
Question regarding Europe what is your P&A exposure?
I am sorry.
John Herrlin - Societe Generale
What is your P&A exposure, plug and abandonment?
John Herrlin - Societe Generale
Well all of your…
Okay. I won’t go into specifics on our exposure there from an abandonment liability on individual asset basis and of course from a competitive standpoint with us going into the market it’s probably not appropriate for me to comment on numbers there, but what I will tell you is that we have done extensive study work. We have an internal process where we periodically look at and retest our abandonment cost and liability for all our assets and we have those numbers internally and available to us so that we can make the appropriate decision as we go into marketplace.
John Herrlin - Societe Generale
Okay great. My follow-up is on the un-conventionals, you mentioned a lot discussion of producing drilling times and overall well cost, could you talk a little bit about what you’re doing on the frac side and also in Oklahoma, is there any way to increase your net to gross much higher net to gross counts in terms of you other plays? Thanks.
Yes well you’re right. You’ve raised a good point which is this is not simply about reducing drilling time. That is an element of what we’re trying to do form a capital efficiency standpoint, but we’re trying to create value from every incremental well and sometimes that may mean spending a bit more on the completion design to ensure that it’s generating the highest PV and the highest PV/I from a capital efficiency standpoint.
I think during and I’ll turn over to Lance in just a moment because I think he can tell, talk a little bit more about our completion design and the evolution of that but we continue that optimization process, this is an area where a Company like Marathon is truly benefiting from the competition among the core service providers. When you think about Halliburton’s, the Schlumberger’s, and the Baker’s they are out there really driving the competitive nature both from a cost commercial standpoint but also from a technology standpoint in fracturing and we benefit from that.
We use all of the three major providers in our operations and we cross-pollinate those learnings across all three of our resource plays to continue to drive our optimization of our fracturing designs. Of course we’re not going to stand here today and give you the full recipe for our fracturing designs because we view that as being a competitive advantage and as you looked at those performance windows that we’re operating in, in terms of where our wells stack up relative to the competition I think you would have say we’re doing a pretty good job of that.
Well with that maybe Lance, if you’d like to offer some comments just specifically on what we’re doing in fracturing and completion design well.
Sure and thank Lee. It’s a great question, the completion efficacy is at the very heart of unconventional resource development, I’d a good portion to spend a majority in my earlier carrier as a completion and stimulation engineer and we have dedicated resources in each of Bakken, Eagle Ford and Oklahoma or their only focused on surveilling our well performance as well as those of our appears and then constantly injecting new ideas into our stimulation process and into the execution flow to improve those well results. You can look at the slides in the book today and look at each of those basins and see we’re improving every single year.
There is almost nothing we haven’t varied in 2013 in each of those basins from fluid volume to perforation cluster spacing to profit loading to rate to the schedule with which we deliver the profit and even the fluid systems themselves. I think everything is on the table for us on a every quarter, every day basis in terms of delivering those results. I think those improvements, I hope speak for themselves and what we learned in only the last several months of this year gives us confidence we’re going to be able to deliver similar improvements moving into 2014 and it’s not simply the stimulation.
I think one of the compelling parts of people having focused on Eagle Ford is a great example, as we move the wells closer together, we’re fundamentally improving the complexity of the stimulation or changing the in situ rock mechanics and we stimulate wells at closer to lateral spacing, we’re driving up recovery efficiencies as we move into that and Bakken at closer spacing, we’re going to see improvements from that and similarly in Oklahoma, we’ve really haven’t even begun to test infill density on our own operated assets. So, we’ll see that increase further.
Addressing your last question, I think in terms of net to gross in the Woodford specifically, we have a lot of locations that are focused on that so the difference is, in Oklahoma the way unitization rules are designed in the regulatory body, it’s easy to form a unit. So we have a very large number of units where we have a relatively modest 7% to 12% working interest and to-date we’ve participated widely in those because they’re valuable and they help us gather data widely.
I think as I remarked in the presentation, we’ve actually owned an ownership in more than one-third of every well and more than one-third of the total Woodford horizontal well, so that we’ll continue to participate on those because we want to monetize our acreage broadly. And then focus on growing our operated piece as much as we can because we feel like we’re improving the value on the operated piece differentially to the peers.
Okay next question please. Hang on just a moment for the microphone please. Please be patient.
Just a question on AOSP you didn’t really mention it with the exception of talking about the cash flows that comes from the asset. On our number that looks like the returns are reasonably low it represents a pretty good chunk of your capital employed and it’s also a pretty good wedge of your production. My question is whether there is a reason it’s remaining in the portfolio, may be a strategic rationale for keeping in the portfolio and then in addition do you believe the long-term value for that asset exceeds the value of which it carries currently? Thanks.
Well, certainly from an oil sands milling perspective, our interest there is very high quality mining operation. We have in the past looked at a marketing effort for AOSP prior to my arrival at Marathon. What I’ll tell you is just again, like every asset we test AOSP and our interest there and our operated interest there to see it’s fit and our overall portfolio. It is a big contributor, it can be a significant contributor as you look back through 2013, we had a tremendous third quarter with AOSP, with it contributing quite a bit of income and cash flow to the operations in it, what it really demonstrated was when our oil sands mining operation has high reliability coupled with relatively good realizations, it can be a significant contributor to our bottom-line.
But the challenge that we’ve had in oil sands mining area has really been a question of getting the reliability up to where it needs to be and working the expense management side of the equation there. It is a high quality mining asset. We want to continue to work with the operator there to drive value. We’ll continue to evaluate this part of our overall portfolio but it is a strong contributor for us and if we can move on the reliability front there’re also some very accretive what we consider to be debottlenecking investments that we’re happy to work with operator on once we get the base business where it needs to be.
I would also argue that similar to my comments on Libya, that today is probably not the day that we would be out there garnering the highest value if we were to see it to monetize that in some other way, but it will remain in the discussion around portfolio management. Thank you.
Evan Calio - Morgan Stanley
Two questions for me. Number one, can you share the tax basis or any friction expected in the North Sea sale? And then secondly, can you quantify how much in your 2014 CapEx you are spending that’s midstream related and any thoughts on midstream monetization strategy? I know you have significant assets invested there. You’re spending increasing amounts in North America. I know John has also had success with that structure’s prior entity?
Yes, and in terms of ultimately if we’re successful with the transaction in the North Sea, our anticipation is that there would be a very minor tax leakage there but of course we need to get a little bit further along in the process before knowing that with certainty but that’s our estimation today. In terms of the midstream spend, I think if you look a little bit deeper into our press release today, we actually talk a little bit and breakout for the U.S. the spend if you will from a facilities kind of midstream standpoint, that number has been right around a couple of hundred million dollars or so.
And really to your other question about our overall investment in the midstream particularly here in the U.S., although we have invested there I would say we’ve invested very efficiently there. And if you look at that cumulative amount of money that we’ve put in to, I would facilities and midstream type of infrastructure it’s a relatively small number to say compared to some of the MLP activity that you might see out in the marketplace.
Guy Baber - Simmons & Company
Lance, I wanted to get your thoughts on the Eagle Ford plateau which you guys have obviously raised, just wanted to get your thoughts on the 150,000 barrels a day there and you got a range around that, your thoughts in kind of pushing that peak higher versus extending it further and if there’re any constrains with respect to on the infrastructure side with respect to getting to the higher end of that range? And then I have a follow-up.
Sure Guy it’s a great question. And I think what we can in starting is it relative to the Eagle Ford assets we purchased and closed on in November of 2011. We initially anticipated a peak production of approximately 120,000 to 125,000 barrels of oil a day. And as we see now that’s going to grow to 150,000 over that same period in fact we’re going to average in 2014 almost our original peak just 5,000 barrels short of it, so we continue to see it grow. Should we have continued success?
Guy, in the infill density at 40 acres and high GOR oil and, additionally, if we have success in co-developing the Upper Eagle Ford in the Austin Chalk together, I think we recognize there is an opportunity for that peak to either potentially grow or for us to hold that flat and extend it additional period of years and leverage the value of the surface facilities that we’ve invested in over that time. So I think we’re fairly confident we’re going to reach that peak and over the next few years, we’ll be issuing guidance as we see where it’s moving between them. But I think it’s a big resource, we are going to continue to aggressively develop it as we have done over the last two years.
Guy Baber - Simmons & Company
And then Lee I had a question just on capital spending, could you just provide a framework for us to think about spending on a go forward basis, one in light of the growth objectives which you’ve highlighted? And then secondly could you talk at all around commodity price assumptions for the ’14 budget including maybe Brent-TI spread so we can get a sense of how that may or may not evolve over the course of the year? And then North Sea if you get give that numbers around how much CapEx has been allocated there the last year and this year? Thanks.
Okay well certainly talking about spending going forward, I think we’re giving very firm guidance today on 2014 and what you see there of course is that 5.9 billion budget and in comparison to the 5.2 billion that we’ve been carrying in 2013, that’s largely reflecting this acceleration. As J.R. had pointed out even with that accelerated spend being brought forward in 2014, we’re largely going still be needing those demand through our own cash flows. We don’t view that as a limiting factor for us from a cash flow standpoint but it does give us good comfort from a financial standpoint to be able to largely fund our growth aspirations with existing cash flows and of course we also can leverage some of the proceed sales that are either transacting or as we discussed potentially may transact in the North Sea.
Going forward, we don’t give forward guidance necessarily on capital but if you look historically this has kind of been in the ballpark where we’ve been in the $5 billion-$5.5 billion range that we’re going let that be driven by the quality of opportunities that we have in front of us, it goes back to those various calls on capital and the priorities that were put on that, it really starts with those organic reinvestments and resource capture trying to bring new resource and then from there, we’re going to look to deliver our competitive dividend, we’re going look to protect and maintain our investment grade balance sheet and then as J.R. said that we’ll look if we have still have excess capital at that standpoint we’ll test the return that we might be able to generate through opportunistic share repurchase.
Just maybe coming back and maybe I’ll say a few words about commodity prices and maybe I ask J.R. to comment a little bit since he addressed that on our slide, you saw of course our portfolio being against 70 plus percent liquids biased, the sensitivity that our portfolio has on commodity pricing. I won’t disclose our pricing deck that we use on our financial case but what I would hope to give you is some comfort that we’re testing our financial case against a reasonable range of outcomes not only on WTI/LOS but also spread and Brent pricing as well of course for us WCS for OSN.
So we’re going to test against those commodity prices make sure that they were robust. We understand where our CapEx is at the margin in case we see a strong correction in pricing and we have the ability to react to that if we need to.
With that, I don’t know J.R., if you want to talk anything else on commodity pricing standpoint.
No. I mean we shared with you the sensitivity there. The other question you asked was with regard to Norway and Norway capital. What I would tell you is 2014 is a high capital spend year for the projects that Mitch talked about earlier. So, when you think about it more from a free cash flow standpoint for Norway and the combined UK assets not as large this next year coming up as you might historically think around your mind set because of the projects like Boyla. And so, again I think it’s an anomalous year at least in terms of 2014 for Norway, UK and you’d expect them in the outer years as a result of Boyla rolling off to that to moderate somewhat.
Next question please, yes sir.
Matt Portillo - Tudor, Pickering, Holt
Two quick questions on the SCOOP looking at your extended lateral well results obviously a very big improvement on the IP rates there, just curious if you could give us a little bit color on how long those laterals are maybe what the well costs are compared to kind of your shorter lateral type curve?
And then also on the completion side, you mentioned you guys are testing a number of new completions across all your plays, looks like you have relatively few stages so far and these wells are kind of 12 to 14 stages, where could that move to overtime as you really kind of progress in this play? And then I have a quick follow-up question after that.
Well, I’ll let Lance jump in here in just a moment since it’s his area. But certainly for the extended length wells we’re basically doubling the lateral length out to kind of nominally the mile kind of distance there. So, that’s really and again, because of the unique attributes in the Woodford we’re able to do those types of lateral lengths and the leases that we have there. Lance maybe you want to comment more directly on that point.
Sure, thank you for a great question. Matt so specifically when we said the 12 to 14 stages could have made it more clear that was largely looking at the single mile laterals of increasing density there. The longer laterals are averaging about 75,000 feet so far we have some approaching 9,000 feet and some more like 6. But that group of longer wells is approaching a mile and a half average and converging and those have similarly as they’re a 50% longer on average at about 50% more stages in that stimulation design overall reflecting that.
So, relative to the single mile wells they are costing more longer to drill as well as the stimulation stage has been a primary driver of between $1 million and $1.5 million of more cost but as you can see from the IP and hopefully indicating their longer EUR that the value perspective is a modest amount of additional cost for a tremendous upside in well deliverability.
Matt Portillo - Tudor, Pickering, Holt
And then just a second question, I know that there has been a lot of questions so far on kind of light crude. You guys have a unique position in the Eagle Ford where you are producing quite a bit of condensate as well. Just curious how you view the marketing strategy for condensate going into 2014, 2015 and kind of your overall view on that market on a go forward basis.
Well, as you well know, the commodity prices on the NGL side have been a bit tougher, certainly as you look at places like the Woodford which can have a great driver from condensate and NGLs, it does make a big difference. The best we can do is again try to maximize our realizations there get our liquids on pipe and get them to the best available market. The team has done a great job of doing that, in fact we’ve been able to get some of our barrels to pretty advantage position there because of transportation et cetera and that’s the main challenge for us is getting to the best market.
We’re still going to be driven by the supply and demand which you see here though in the U.S. which is just a reality that we’re living with today, clearly we’d like to see recovery in condensate and NGLs because they would be overall very accretive to incremental wells not only in the Eagle Ford but also in the Woodford. Sorry yes over here.
Mike Kelly - Global Hunter Securities
Hi Lee this is Mike Kelly with Global Hunter Securities. Given the disclaimer that your 5% to 7% production growth would carry over the next five years, excludes exploration success. I was just hoping you could quantify or give some additional color on a reasonable success scenario on the exploration side and what that could do to that 5% to 7% rate? Thank you.
Well you want me to turn that one over to you Annell, well may be tell Annell comment in a moment but clearly we internally look at those kind of what I would consider to be portfolio adds from a volumetric standpoint and how those come in and are accretive to our overall volumes outlook, we don’t of course include those in our firm volumes outlook because of the geologic risk that we experience in those but, I want to leave you with a comfort that Annell's team is very much focused on what those success cases will look like and we test those success cases internally in terms of their overall contribution.
I think Annell mentioned we're looking at adding a couple 250 million barrels of resource this year, our ultimate goal though is to drive that resource to reserves and to production, and it's very difficult at times to put timing elements on these as well, we just look at the pace of development today in Kurdistan, I mean we're seeing success there but we equally know that for export solutions to present themselves it's going to probably take a little bit of time to get those sorted out.
So there're a lot of variables there and that's one of the reasons why we typically strip those volumes out of the guidance that we provide externally because they are a bit unpredictable. But we have to have that path of profitability very clearly defined, because just as every other investment our exploration investment which is running right around $500 million a year, must compete for capital and must ultimately show a return on our shareholders' investment. Annell, would you like to add anything?
Well I think you said it well which is really the issue based on timing, because you said, being between now and 2017, so we have Kurdistan certainly in the program that's moving ahead and if you look back at Shenandoah and Gunflint, you know Gunflint will come online, Shenandoah's looking at I think 2018. So it's 2017, 2018, it's in that timeframe, so it's really the timing issue and that's part of it. And then of course we make the decision at the time of success, do we operate and develop, do we monetize, what else is in our portfolio and what else do we want to do and so I think those are the reasons why we leave it out for now.
Yes, and of course it's also the variability and the development type you know, a tieback in the Gulf of Mexico, we can turn much more quickly than say a full green field development in the deepwater in the Gulf of Mexico, so, for a project like that you're talking five years out to actually production on which really doesn't quite pull some of that into the window, so it's also the. We hope we have that problem to work, right that we have a very successful discovery and we're having to ask the question about whether or not it justifies a green field development, but that does move those barrels out in time a little bit. Thank you for the question.
Mike Kelly - Global Hunter Securities
If I could do a quick follow-up just on the UK and Norway asset sale, what is the PV10 value on those assets and is that a decent kind of start-up metric for us to think about what that could garner in a sale here?
Well I'll leave it you to do those preliminary evaluations for reasons I stated earlier with us going into the marketplace. We're not going to talk about preliminary evaluations today, that's a topic for another day for us, but clearly we understand the assets very clearly both on the UK and the Norwegian side internally, we'll be able to look at the potential retention value of those assets and that'll be compared directly to the value that we might be able to capture in the marketplace. And I think, we presented probably enough information today, where most can do a reasonable estimation based on whatever set of metrics you care to employ, so. Thank you.
Lee, we've had a number of questions on the Internet, from there and most of those have been answered. One that I don’t believe has is around financial discipline it says you had a stated goal in the past of living within cash flows with the increasing capital and strong dividends that combined appear to outstrip cash flow estimates in 2014, has that philosophy changed?
No, I would say the philosophy itself hasn't changed I think as a leadership team we've never really viewed cash flows as a limiter. We viewed it as a healthy way to run the business, but we prefer to be more opportunity driven and we're going to fund those high quality opportunities.
In the case of the 2014 budget, we saw opportunities there that were accretive, that justified moving a bit beyond our operational cash flows, however keep in mind also that we have proceeds that have come in from, of course cash flows in previous year and through 2013 as well as some of the divestment, successful divestments that we've been able to make in 2013. So I think within that broad mantra of living within our cash flows that we’re still really adhering to that, if you look at both operating cash flows as well as potential proceeds from divestment.
Krim Delko - Orange Capital Partners
Hi, Krim Delko, Orange Capital Partners so two questions, one do you have hedges in place, and if so, what are they and second, do you see opportunities for un-conventionals outside of the U.S., or what's your view on that topic?
Okay sure maybe if I could take the last one first on the unconventional. The success that we’ve seen in the U.S. conventional, unconventional space has really been quite unique and it's been driven by some of the very unique attributes that the U.S. has. It all starts with of course the quality of the resource and the U.S. has been blessed with some extremely high quality resources in the unconventional space, secondly though we also have royalty ownership in the U.S. and so the royalty owners benefit directly from the development of their leasehold which is a, of course a very compelling element of the U.S. success case.
The other piece is we have a very extensive infrastructure and a very liquid market here in the U.S. which also drives some of the development, we have a very well developed service industry sector here as well, and so as you, it's a bit beyond just having the high quality rock and there're many places around the world that likely will have high quality unconventional shales. You can look at the Bakken Muerte in Argentina, you can look at other places around the world where folks are testing, Germany, Poland, et cetera. But many of those locations don't benefit from some of those other intangible items, more tangible items that I just went through in the list for the U.S.
I think because of that, the pace of that development will likely look different than it does here in the U.S. There are a lot of things that have contributed to driving the pace and the success that we've experienced in the U.S., that in my view are simply not replicated today in the international space and so I think that's going to continue to be a challenge. Your other question I think was around hedges and of course we have disclosed our hedges of course for 2013 previously, hedges and certainly foreign part of our risk management strategy just as looking at our exposure between WTI and Brent, and so we look at that more I would say as a holistic risk management strategy of which hedging is just a component, and so I don’t know, J. R. if you'd like to add anything to that.
J. R. Sult
No, I think that's good Lee, what I would say is Marathon historically has been opportunistic in hedging a portion of its production. We don't have any material hedges in place well beyond 2013 but I think that's something that this management team will continue going forward and we’ll be opportunistic but again for a portion of our production. Don't forget we've got a very, very strong balance sheet that backs us up, it gives us a great deal of flexibility from a financial standpoint.
Thank you, next question.
Thanks very much, first just a small housekeeping item. After you exit Angola and presumably the North Sea, have you calculated what your income tax rate will be?
We've certainly looked at projections where we look at our effective and statutory tax rates you know, under those scenarios, absolutely.
Anything on that?
I mean we're kind of dealing a little bit with hypothetical there, I prefer to maybe address those, as we get a little bit further along in the process, I think it goes without saying that we all know the relatively high statutory tax rate that exists in Norway, we have actually some tax information embedded I believe in the materials that we distribute today which really outlines those statutory rates and the volumes percentage that those tax, that were subject to those tax rates, so that's in the material that we provided today. Clearly though the Norway barrels are at a relatively high marginal tax rate and so we’re looking at bringing some of that margin back into the U.S. barrels.
Okay, I just might add on given the fact that when I accepted the role at Marathon, my predecessor told me that you guys were of course always peppering her with tax related questions, but you can see from that material in the appendix our tax rate is declining as a result of the growth in Mitch's business here, and so you definitely can expect in the event we are successful in disposing of those assets and your assumptions with regard to our Libyan production that those rates are going to continue to come down.
And just a follow-up on your exploration program, so looking at the 2014 target, your average working interest is about 30%, in the prospects. Is that a good rule of thumb going forward or do you aim to increase or decrease that?
Yes well I think again, again building on some of Annell's comments, when we get into exploration activity, we'd like to go in with a material operative position because it does present us some optionality there, a good example of that is, we have talked a little bit about Madagascar, that is currently drilling, that's an area where we farm down and promote into that well, and that was a risk management strategy in our view, so when you can come in with a material level of equity it gives you a lot of optionality and then based on your perception of the above ground, below ground risk, you'll gear how much capital you want to expose there.
Another good example then, in our Kurdistan operative blocks we actually have those initially at 100% equity and we farmed those down as well. So I would say that we used that a bit as a risk management strategy but we want to have materiality. That's a key element of our exploration program, and then as we learn more we'll adapt the appropriate risk management strategy for the specific prospects. So I guess I would warn you not to necessarily use that 30% as an indicator because the exploration program is a little bit lumpy. It comes in and we do wells in a given year based on rig availability and the appropriate timing and the commitments we've made to host governments, so I’d just say be careful.
I think the probably the better metric to use would be that we’re looking to try to drill around eight of these very high impact wells, per year, we've committed for instance to as Annell mentioned bringing in a new drillship in the Gulf of Mexico, which is going to allow us to run that program, really for the next three years which is the primary term of the rig. We've got a very deep inventory of prospects that we're excited about and so to the extent that you can use that information to try to get a better handle on our go forward equity but I'll just caution about drawing a tramline through the 30%. Yes, in the back of the room.
Jay Saunders - Jennision Associates
Hey, Lee it's Jay Saunders from Jennision Associates. Thinking about the 5%-7% production growth guidance, what's then now versus previous, given that you're accelerating in North America and maybe Kurdistan's in there. What's offsetting that and maybe it's Block 31. And what's the apples-to-apples, what would the growth rate be under the previous assumptions?
You hit upon it already, which is, what you basically have occurring is, you have the acceleration of the U.S. resource play that Lance described, essentially coming in and displacing some of the Angola volumes that we’re exiting so to kind of get that on apple to apple basis, that's really what's occurring in that 5%-7% number.
I also want to be in the sense of transparency, to be very clear that that 5% to 7% number also includes contributions from our Libyan production overtime, so there is an assumption in there, even though we carry Libya results financially they're below the line. That particular volumetric metric does have Libya volumes returning to normal in 2014 going forward.
Jay Saunders - Jennision Associates
So basically it’s a wash the growth in North America offsets Block 31 and is Kurdistan in there?
Well there is certainly elements of Kurdistan where we have approved field development plan which would be in Atrush but again there are no exploration success volumes in there, so while we have a proved field development plans, at the non-operative, top operative Atrush those volumes would be accounted for. And I would just come back to saying, offset, I would argue that there's still some play between the 5% to 7% and clearly there is an offset in the nominal sense, but we feel very good about the volumes that we're bringing in to the portfolio, from the Eagle Ford, Bakken and Woodford.
Jay Saunders - Jennision Associates
Sorry, is it more than just than Block 31 on the offset?
Well I mean again, there's a range on that and I think Lance shared that range, that's what’s driving that 5% to 7%, but let's just put it like this, you know, we remain very confident in our ability to deliver within that range.
Lee, another question off the Internet, guidance on Marathon's effective tax rate in 2014 of 48% to 55% that's significantly below current 2013 guidance, could you explain why, is this benefit likely to continue past 2014?
I want to J.R. to jump in, but the basic answer to that is that we continue to of course rate our volumes more heavily to the U.S. the onshore resource plays, and as J. R. already mentioned that naturally is causing our production mix to change overtime. And that's really of course adds to the discussion we've been having on any of the North Sea divestment or North Sea marketing, so overtime, as we continue to see the increase in the U.S. volumes that is having a moderating effect on our tax rates going forward in time. Thanks, Howard another question, yes sir?
Matt Portillo - Tudor, Pickering, Holt
Matt Fortier from Tudor, Pickering just another follow-up question, as, if you guys think about kind of monetization options in Gabon, and kind of what’s the gas discovery so far, what sort of options are available to you today, or is really the intent to try to find a different phase window here where you're chasing more kind of an oil play in the region? And then I guess the second question is, have you seen your results and maybe some of those results further south in Angola it does seem like the GORs are kind of the gas ratio tends to be a little bit higher so far from what we’ve seen, how does that kind of influence your drilling plans in the basin?
Well, I'll let Annell jump in here in just a minute, but first I'll just say, on Gabon, we did have one gas condensate well, first deepwater, pre-salt discovery in Gabon, that was on a block that is a 2.2 million acre block with a lot of prospectivity on it, we absolutely want to continue to test that block to see if we can find an oil leg in that block.
Clearly West Africa gas has that kind of quantity it would be a challenge for us, it doesn’t really fit within our profile, so our goal there is to really try to seek out and see if there is oil potential. I think our confidence in that, is somewhat supported by the fact that we were very active participant in the Gabon bidding round.
So and course we bid as an operator there the Alba block of course is non-operated for us. So the two blocks that we were higher bidder, we are the operator, we see a lot of prospectivity there as you move to the block to the south we are getting much closer to the inboard the more inboard oil discoveries that have already been made, so perhaps there're other sources there as we might be able to see also in the Diaba block, Annell?
Well, first of all in terms of the Diaman well that we just drilled there are adjacent prospects along turn and within closure that if that's something to pursue that could make that larger, if that ends up being say all gas and condensate. But we are waiting for the further fluid analysis on that before we make that. And then just like Lee said the other prospectivity on that block is in adjacent to source areas that are potentially oil-prone. So we could see a mix in there on that, and like you said the prospectivity that we addressed and attending a bid around and going after the other blocks.
But there you’re looking at different areas and different source areas so even comparing it to what’s been seen in Angola is a complete disconnect those are completely different basins. And so you really wouldn’t compare them, and they may be quite different within each area you drill pending the source area that’s focused on.
Yes, Annell as I would also add consistent with what Annell’s comments were in the presentations we also have a very long operating history in Gabon as a company so we have a lot of relationships there in country we feel very confident that in the event that we have discoveries our ability to act as a developer and operator there our confidence is quite high. Thank you. Other questions, we have right down here in front well he is coming Doug hang on.
Doug Leggate - Bank of America
Thanks Lee. Doug Leggate from Bank of America, just wanted to two quick follow-ups please given that you mentioned Libya, could you just give us a status update to help things out there what gives you the confidence that you can have those volumes back? And secondly the proceeds obviously from UK and Norway along with your strong balance sheet and your share buyback program you’re clearly in pretty fleshy state in terms of cash how do acquisitions feature into your thinking in the future given there is a lot of companies’ resource rates that don’t have balance sheet you have?
Okay, let me come back to your acquisition question in just a moment, but let me address the Libya first. And I’ll make a few comments and maybe I might ask Mitch he is a bit closer to the action to comment there. I don’t want you to confuse our assumption in the volumes model with having some inside on when we might be able to see a return to production there. Just like the folks in this room we were watching the situation very-very closely there it is our hope that, that can be resolved peacefully. But I will be honest we did not have a clear understanding of when that will occur. Mitch would you like to add anything?
Sure I think I can add just a little bit more color to that. We’d like to be able to sit here and say we’ve got clear line of sight to a resolution. The fact of the matter is it’s a difficult situation for them it has been handled peacefully and we’re encouraged by that. We have signals from contacts on the ground that would suggest a resolution might be very nearly in hand. We could see resolution this month and return to production this month.
And on the far side of that spectrum is speculation that this could go on for months and towards the end of next year and I think those are both reasonable endpoints. We’re cautiously optimistic from the contacts that we have on the ground there that we’ll at least see some near-term resolution and then the sustainability of that I guess would be the large question going forward.
So let me come back to your second question Doug around business development and acquisition activity. First of all I hope from today’s presentation you can see that we have a very strong growth portfolio in and up itself today and that’s really what we attempted to describe in today’s remarks. So we don’t feel forced today to take any action. And certainly I would now want to pursue an action that would be viewed as dilutive to overall shareholder return.
However, in my discussion around one of the primary challenges being acquisition to new and material resource there are really two ways for us to be there. There is Annell’s program through exploration and then of course there is opportunistic business development. And I thought it was a very compelling slide when I showed that pie chart that showed the contribution from those business development successes that Marathon had pursued in the past.
So what I will tell you is that with our balance sheet with the strength of our financial discipline with our cash flows certainly we’re going to be opportunistic as the right collection of opportunities come forward we’re going to evaluate those we do evaluate those on an ongoing basis. And again we can be a very -- we can be a buyer that can act with high transactional certainty which is a very attractive trade. And we can -- and so we’ll continue to look at those kind of opportunities as they come forward.
But again my point is that we’re not looking to necessarily go out and do something immediately out of the sense of urgency here. This is really about making the right decision around the portfolio which is the North Sea marketing in terms of what that might lead to in the future in terms of additional opportunities I view that as an independent discussion, other questions?
We have no further questions from the Internet either Lee.
Okay, well with that I’d first like to say thanks to each of you for attending today. This was a very important meeting for the new leadership certainly for our employees and also for our shareholders. I’d also maybe like to ask you to join me in thanking my leadership team for all the excellent work that went into today as well, as I really appreciate the work that they’ve done.
And I would just add that I very much appreciate the time. I know December…[Call Ends Abruptly].
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