Good morning. Welcome to Devon Energy's Fourth Quarter and Year-End 2012 Earnings Conference Call. (Operator Instructions) This call is being recorded. At this time, I would like to turn the conference over to Mr. Vince White, Senior Vice President of Communications and Investor Relations. Sir, you may begin.
Thank you and welcome everybody to today's fourth quarter and year-end 2012 earnings call and webcast. Today's call will follow our usual format. I will cover a few preliminary items and then I'll turn the call over to our President and CEO, John Richels. John will provide an overview of our 2012 results and his thoughts on the year ahead, and then Dave Hager, Head of Exploration and Production, will provide an update on Devon's reserves activity and operations. Following that, our CFO, Jeff Agosta, will finish up with a review of our financial results as well as specific guidance for 2013. After Jeff's discussion we'll of course have a Q&A session. And I want to remind everybody that our Executive Chairman, Larry Nichols, as well as Darryl Smette, the Head of Marketing, Midstream and Supply Chain, they are both with us today. As usual we'll respect your schedule and conclude the call after one hour.
Later today we will file a Form 8-K that will provide specific detailed forecast for all of our operating items as well as our capital budget for 2013. The guidance section of our website will contain a copy of that 8-K and other forward-looking estimates that we mention in the call today To access that guidance, just click on the guidance link found in the Investor Relations section of the Devon website.
Please note that all references today to our plans, forecast, expectations and estimates are forward-looking statements under U.S. securities laws and are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance. You could see a discussion of the risk factors relating to these estimates in our Form 10-K. Also in today's call, we'll refer to certain non-GAAP performance measures. When we use these measures, we're required to provide related disclosures. Those can be found on Devon's website.
Before I turn over the call to John, I want to comment on the $896 million property impairment charge taken during the fourth quarter. This resulted principally from the full-cost accounting ceiling test. It is a non-cash impairment charge and it resulted from the decline in natural gas and NGL’s prices over the past 12 months. Just to be clear, this write-down is simply an accounting exercise and is not reflective of the fair value of our assets. The impairment charge has no impact on cash flow, cash balances or credit agreements and is not indicative of the future cash flows we expect to generate from our assets. It’s worth noting that this charge is not unique to Devon. Several companies in our industry have taken these impairment charges throughout 2012.
When you exclude the impairment charge and the other items that analysts typically don’t put in their estimates, our non-GAAP earnings and cash flow for the fourth quarter was $0.78 and $3.11 respectively per diluted share. Both these results exceeded street expectations by a comfortable margin.
At this point I’ll turn the call over to John Richels.
Thank you, Vince. Good morning everyone. 2012 was a year of achievement and challenges for Devon. While weak price realizations definitely hurt our financial results for the year, we continued to make significant progress towards the conversion of our portfolio to higher margin oil production.
We drove 2012 oil production up 20%, more than offsetting declines in natural gas. In fact, production from our North American asset base climbed to an all-time record of 250 million oil equivalent barrels. This production growth was led by year over year Permian Basin oil production growth of 31%.
With the aggressive transition of our product mix, liquids production has now reached nearly 40% of our total volumes at yearend. We have also significantly increased our development inventory in the Permian through our successful Bone Spring and Delaware programs. Over the past year, our risk resource from these two plays has more than doubled.
In 2012 we also successfully entered into two exploration based joint ventures that are delivering nearly $4 billion in value to the company. This included $1.3 billion in upfront cash payments, along with $2.6 billion of future drilling carries that will fund 70% of Devon’s drilling costs in our new venture plays over the next couple of years.
While the upfront cash payments alone more than compensated us for our acreage and early exploration costs, these transactions also significantly improved the capital efficiency of our go-forward programs.
Our exploration work on the joint venture assets is delivering very promising results in the Mississippian play in Oklahoma, the WolfCamp and Cline Shale in the Permian Basin and in various oil plays in the Rockies. In aggregate, Devon has exposure to over 1 million net acres in these plays.
On the liquidity front, our balance sheet remains in terrific shape and continues to be one of the strongest in the peer group. At December 31, we had $7 billion of cash and short term investments and a net debt to cap ratio of only 18%. This position of strength helps us comfortably fund our transition through an oilier production mix.
And finally, with the 2012 capital program weighted towards oil projects, we had strong growth in oil reserves. Our oil reserve additions reached almost 260% of 2012 oil production. Dave will provide more details on the results of our 2012 capital program later on in the call.
Looking now to this year’s activity, given the pricing environment we’re facing in 2013, our capital program is designed to enhance capital efficiency by concentrating spending in core development regions and derisking our joint venture acreage while significantly reducing investments related to acreage capture. We expect our E&P capital expenditures in 2013 to decline by more than 25% to a range of $4.9 billion to $5.3 billion. This includes $200 million for routine leasehold acquisitions, which is roughly $1 billion less than the spend rate in 2012.
Even with our reduced E&P budget for 2013, we expect to maintain drilling activity levels similar to that of last year. This is a result of significantly higher drill-bit activity on our joint venture projects where our partners will fund most of the total well cost. In 2012, the benefit from our drilling carries amounted to approximately $400 million, and for 2013 that benefit will climb to around $1 billion. We will also have a very active year expanding our midstream business. In 2013, we plan to invest around $1 billion to finish our plant expansions in the Barnett and Cana, roughly double the capacity of our access pipeline in Canada, construct a new gas processing facility in the Ferrier area of Western Alberta, and build out infrastructure in the Mississippian play and in the Permian Basin.
Total capital spending for 2013 after you include the midstream capital, E&P capital, capitalized G&A and interest and corporate capital, is expected to come in somewhere between $6.4 billion and $7 billion. The majority of our 2013 E&P dollars will be devoted to oil driven development projects. This focus will translate into oil production growth in the mid-teens over 2012. Our oil production growth in 2013 should come almost entirely from light, sweet crude in the U.S., which is expected to grow roughly 40% over 2012 levels.
The aggressive development of the Permian basin will be supplemented by the early stage development of the Mississippian. On the liquids-rich side of the portfolio, we will limit drilling to only the most economic liquids-rich portions of our Barnett and Cana fields. This activity will generate NGLs production growth in the range of around 10% to 15%. And lastly, similar to years in the recent past, we will not pursue dry gas drilling during 2013. The lack of investment in dry gas will lead to year-over-year natural gas declines of about 8% to 10%.
Summing up our forecasted production. On an energy equivalent BOE basis, we expect production to be essentially flat versus 2012. However, given the sustained divergence in the value of oil and natural gas, it's become pretty obvious to just about everyone that the energy equivalent BOE conversion rate of 6:1 has been rendered meaningless from an economic perspective. Based on the current price realizations of our oil and gas mix, a value or price equivalent is a much more meaningful way to evaluate growth in the value of a hydrocarbon stream.
From this perspective, applying a relatively conservative oil to natural gas price ratio of 20:1 to the midpoint of our 2013 production guidance, yields 7% overall growth for the year. Now let's switch gears a little bit. Over the past year, Devon's stock price performance has clearly been a source of frustration for us as well as for our shareholders. The headwinds that we faced in 2012 were principally the result of our product mix and weak price realizations for natural gas, natural gas liquids and Canadian oil. Those three products, together comprised over 90% of our production. However, independent of these depressed price realizations, it's been noted by us, by many of our shareholders and by other industry observers, that Devon's current stock price does not adequately reflect the underlying value of our assets.
For those of you who have followed Devon over the years, you know that we have never hesitated to make bold moves to unlock value or to return capital to our shareholders. For example, at times in the past when conditions were right, we have been very active sellers. In fact in the last decade, we sold more than $18 billion of assets at very favorable prices including the assets that we disposed in the strategic repositioning of our company to focus on the North American onshore business. We also executed highly favorable and innovative joint ventures to improve our capital efficiencies and mitigate exploration risk. And over the same period, we bought back almost 25% of our common stock which is more than any other independent in this sector. And finally, we have increased our dividend almost every year since 2004.
In 2013, our board will once again look at the prospect of increasing our dividend. As we move forward, I can assure you that in addition to continuing to work to increase the oil weighting in our production mix, we are examining and considering any and every initiative to unlock value that makes sense from a long term value creation perspective.
While we’re not investing because assets do not currently compete effectively for capital within our portfolio, we’re considering how we might monetize or bring forward the value associated with those assets. Similarly, if we have assets that we do not believe are being appropriately reflected in our stock price, we’re working to determine how that value might be realized or more appropriately reflected in our stock. However, anything we do must be thoughtful and smart and must enhance long term value. We will not pursue a short lived bump in the stock price at the expense of sustained value creation. But I can absolutely assure you that we will leave no stone unturned in looking for true value creation opportunities.
One potential opportunity that appears to have promise is the creation of a Midstream Master Limited Partnership. Now those of you who have followed us for some time may recall that we came very close to creating an MLP for our midstream business in 2007. Prior to completing that transaction, we determined that capital markets were not right at that time to generate meaningful accretion for our shareholders. However, many things have changed. Today, capital markets are deeper, yields in the MLP market are lower and structural enhancements have occurred that have caused us to reexamine whether moving midstream assets into an MLP may make sense. We’ve now retained investment bankers and specialized legal counsel to assist in that evaluation. That’s just one example of the opportunities that we’re actively considering and evaluating to unlock value in our company.
So in summary, we remain committed to our top strategic objective and that is optimizing long term growth and cash flow per share adjusted for debt. To meet this objective in 2013, we will aggressively invest in oil driven projects while letting gas volumes decline. We simply refuse to compromise value by funding projects with low rates of return to deliver topline growth based on near meaningless energy equivalency metrics.
Our capital programs continue to drive strong production growth rates on the oil side of our business while simultaneously expanding our oil resource base to provide future growth. This is evidenced by both the significant expansion of our development inventory in the Permian and the ongoing exploration and derisking of our emerging oil plays.
So with that, I’ll turn the call over to Dave Hager. Dave?
Thanks John. Good morning everyone. I’ll start with a quick review of the impact of our 2012 capital program on reserves. Overall, proved reserves of oil, gas and NGLs totaled 3 billion barrels of oil equivalent on December 31. Drill-bit reserve additions and by drill-bit I’m referring to discoveries, extensions and performance revisions, totaled $381 million BOE or over 150% of our 2012 production.
Not surprisingly, the largest contributors to these reserve additions were from our core development areas, the Permian, Jackfish, Cana and the Barnett. It’s also worth noting that we did not achieve these results by significantly increasing our pad count. We ended the year with just 28% of our total proved reserves classified as proved undeveloped. This is obviously very low compared to industry norms.
These reserve additions were achieved with drill-bit capital $7.5 billion. This includes $7.1 billion of E&P capital plus capitalized G&A and interest. This gives us an F&D cost just under $20 per energy equivalent BOE. As John mentioned, we received $1.3 billion of cash proceeds upon our closing our Sinopec and Sumitomo joint venture agreements. If you net the $1.3 billion of cash proceeds against our drill-bit capital, our drill-bit F&D costs come down to about $16 per BOE in 2012, a very competitive result.
Revisions related to price reduced our companywide proved reserves by 171 million BOE. This is entirely due to the impact of lower natural gas and NGL prices in North America over the past 12 months. Lower prices reduce the theoretical economic life of some gas and liquid-rich gas projects, thereby decreasing proved reserves. Importantly, with our 2012 capital program largely focused on oil projects, we have replaced nearly 260% of our oil production during the year. These oil additions help drive our oil reserves to 27% of total reserves. Including NGLs, liquids now comprise 47% of our total proved reserves.
Shifting now to our fourth quarter operating highlights and 2013 plans, starting in the Permian Basin. Our Permian production averaged a record 66,000 barrels of oil equivalent per day in the fourth quarter, up 24% over the fourth quarter of 2011. Looking specifically to our Permian oil production, it grew 31% over the same period, with light oil now accounting for 60% of our total Permian volumes.
In the fourth quarter, we took advantage of favorable conditions in the rig market to secure several additional rigs for our expanded 2013 Permian program. We currently have 29 operated rigs focused on Permian oil production. This year we plan to spend about $1.5 billion there drilling some 300 wells. Our activity spans numerous light oil plays from development to exploration. Our Permian development plays generate some of the best returns in our portfolio. In 2013, our Permian oil production growth is expected to approach 40%.
At year-end, we had a large number of wells waiting on completion. We are currently catching up on these completions so our Permian production growth should accelerate into the second quarter. A key driver of our Permian oil growth continues to be our Bone Spring's horizontal program in New Mexico. We recently added a couple of rigs and now have eight operated rigs working in the play. In the fourth quarter, we brought ten Bone Springs wells on line with 30-day IP rates of 790 barrels of oil equivalent per day. 75% of which was light oil.
As we mentioned last quarter, we have had considerable success in regenerating our inventory in the Bone Springs. Our drilling success combined with our ongoing geologic evaluation has once again allowed us to increase our inventory. We have now identified 700 remaining Bone Springs locations, more than doubling our previous count. This multiyear inventory represents roughly 140 million barrels of net risk resource potential to Devon. Accordingly, we ramped up our program for 2013. We plan to invest approximately $400 million of capital into Bone Springs and drill roughly 85 wells.
Also in the Permian, we continued to have very good results with our two rig program targeting the Delaware formation. We brought five wells online during the fourth quarter with 30-day average IP rates of 500 barrels of oil equivalent per day. 85% of which was light oil. Like the Bone Springs, continuing drilling success and geologic work has allowed us to triple our drilling inventory to approximately 600 risk locations in the Delaware. In our JV with Sumitomo, the partnership has 556,000 net acres on the eastern flank of the Midland basin and along the Eastern Shelf. We are testing a number of formations including the Cline Shale where we experimenting with various landing zones, lateral lengths and completion techniques in an attempt to understand the optimum approach.
Accordingly, the six wells we had brought online to date have had highly variable results. As we continue to make progress in understanding the reservoir and refine our completion techniques, we are confident that this may mature into an economic play. In 2013, we are writing a four-rig program. Expect to drill approximately 30 across this exploration acreage, testing multiple formations. Keep in mind, our joint venture agreement is allowing Devon to look at these exploration opportunities with very little impact from a capital perspective. Our share of capital for this exploration program will total approximately $140 million this year.
Also within the JV, we have been derisking our acreage that is prospective for the Wolfcamp shale in the Southern Midland basin. During the fourth quarter, we brought six horizontal Wolfcamp shale wells online with 30-day IP rates of up to 795 barrels of oil equivalent per day, including 560 barrels of oil. This program is now delivering consistent, economic results. As a result, Devon and its joint venture partner are pursuing a more aggressive development program in 2013. We are running a five rig program and drilling approximately 110 wells. After the benefit of our drilling carry, we expect to spend about $150 million in the play this year.
Devon has established a very large position in the Mississippian oil play located in north central Oklahoma. We now have approximately 600,000 net acres in the play, with roughly one fourth of this acreage in our JV with Sinopec. This position holds a potential to be a very large oil play for us. We’ve been ramping up activity and are currently running 15 operated rigs drilling both the Mississippian and Woodford shale targets.
In the fourth quarter, we tied in seven wells within the JV area. These wells were brought in line with 30 day IP rates of 335 BOE per day including 210 barrels of oil, above the high end of our tight curve expectations. Since yearend we’ve brought on an additional 16 wells and have another 57 wells in various stages of completion. Because of pad drilling and the necessary infrastructure build out, we’ve been running a large backlog of wells drilled but not yet producing.
Our testing of various frac sizes as well as different landing points within the Miss is ongoing. But we continue to believe the key to optimizing development of the Mississippian play will be the integration of 3D seismic data, production data, logs, core samples and work to develop a comprehensive reservoir model and improve overall well performance. To this end, we have already obtained some 3D seismic and expect to have 3D over essentially all of our acreage by the end of next year.
Our drilling results should begin to reflect the benefits of this approach as we progress through the year. Even without the benefit of the improvements that we anticipate, our results to date support our economic view for this emerging play.
In 2013, Devon and our partner will spend some $1.2 billion of capital in the Mississippian and participate in approximately 400 wells, including about 300 operated wells and about 100 OBO wells. Roughly two thirds of our drilling will focus on our acreage inside the JV with the balance focused on derisking our acreage to the north and northwest. We expect to add at least five additional operated rigs as we go through the year.
Shifting now to our thermal oil projects in northeastern Alberta. Aggregate production from our two Jackfish projects averaged roughly 49,000 barrels of oil per day in the fourth quarter. Production in our Jackfish 1 project ramped up significantly quicker than expected following scheduled maintenance in the third quarter.
This further exemplifies the project’s best in class performance from both a plant reliability and production efficiency perspective. Looking ahead, the widening of heavy oil differentials has pushed expected payout at Jackfish 1 to midyear. As a reminder, we’d expect our post payout royalty at Jackfish 1 to be between 20% and 25% versus our current 5% to 6% pre payout rate. With this delay in payout, we now expect Jackfish 1 production to average roughly 30,000 barrels per day in 2013 net of royalties.
At Jackfish 2, fourth quarter production increased to 20,000 barrels per day net of royalties. Drilling operations have been concluded and completion operations have begun on an additional well pad at Jackfish 2. First steam on this pad is expected late in the fourth quarter. Construction of Jackfish 3 continues on schedule with approximately 50% of the project now complete putting us on track for a startup around yearend 2014.
At Pike, this winter’s drilling -- winter appraisal program is well underway. We plan to drill 35 stratigraphic wells and shoot approximately 55 square miles of seismic. The program should substantially complete the evaluation of the first phase of the Pike development and engineering work is ongoing. As a reminder, the Pike 1 development project will have gross production capacity of 105,000 barrels of oil per day. Devon operates Pike with a 50% working interest. In total, we expect to spend approximately $870 million on our thermal oil projects in 2013.
As highlighted on previous calls, we have been investing in a multiyear exploration program to evaluate the oil and liquid-rich resource potential of our substantial Western Canadian acreage position. Based on the results, we are moving forward with the development projects in the Ferrier corridor area in Western Alberta. Devon has roughly 240,000 net acres prospective for the Cardium oil and liquids-rich lower cretaceous zones including the glauconite.
The first phase of development is focused on about one-third of our acreage position and represents more than 100 million barrels of reserve potential. In conjunction with this development, we are constructing a gas processing facility with an inlet capacity of 100 million a day and liquids processing capacity of approximately 13,000 barrels per day. Construction is slated to begin in the second quarter of this year with completion scheduled for mid-2014. We will begin ramping up our drilling activity late this year with 13-wells planned for the fourth quarter. We also plan to test the potential beyond the currently sanctioned development and expect additional phases in the future.
Moving to the Texas Panhandle and the Granite Wash area. We continue to see solid results. We brought seven operated wells online during the fourth quarter, highlighted by the results of our third Hogshooter well. The Willis Luther 9-8H located in Wheeler County had a 30-day average IP rate of 2,800 BOE per day, including 2,100 barrels of light oil and 440 barrels of NGLs. In 2013, we plan to invest approximately $200 million of capital drilling roughly 50 wells. Our four-rig program will be focused on exploiting the Hogshooter and Granite Wash potential across our acreage.
Moving to our Rockies oil exploration program. We've been testing several different formations with our most encouraging results to date coming from the Turner and Frontier. In the fourth quarter, we tied in our second Frontier well. The Iberlin Ranch Fed 2826-2FH had a 30-day IP rate of 975 barrels of oil equivalent per day including 888 barrels of oil. In 2013, we plan to invest approximately $30 million of capital and drill roughly 25 wells in the area. Our four-rig program will focus on exploiting our success in the Turner and Frontier. And just as a reminder, we expose very little capital compared to the activity level as this is part of the JV with Sinopec.
Moving now to the Cana Woodford Shale in Western Oklahoma. We continue to achieve excellent results from an efficiency standpoint with pad drilling. In 2012, we reduced our average drilling days by more than 20% compared to the previous year. In the fourth quarter, we brought 29 operated wells online with average 30-day IP rates of 6.5 million cubic feet equivalent per day, including 550 barrels of liquids per day. These results continue to be among the best wells ever drilled at Cana with average EURs approaching 10 billion cubic feet equivalent.
Fourth quarter production increased 31% over the year-ago quarter and 15% over the third quarter of 2012. Cana's fourth quarter production growth was led by oil and NGL growth of 68% over the year-ago quarter to 4,500 barrels of oil and 13,200 barrels of natural gas liquids per day. In 2013, we plan to invest approximately $550 million of capital at Cana and drill 150 wells, focused entirely in the oil and liquid-rich core. We are currently running 13 operated rigs. However, should our drilling efficiencies continue to improve at Cana, it's likely we'll trim our rig count as we move through the year.
Shifting to the Barnett shale in North Texas, in the fourth quarter we had 10 operated rigs running in the oil window and the liquid rich core. Our net fourth quarter production averaged 1.4 BCF equivalent per day, up 3% from the year ago quarter. In 2013, we plan to invest approximately $500 million of capital in the Barnett and drill approximately 150 wells. We currently have 10 operated rigs running but planning to drop four of these rigs over the next couple of months. Our liquid rich focused drilling program in the core of the play continues to generate competitive returns.
In summary, our 2012 capital program delivered strong oil production growth and we are on track to repeat this in 2013.
With that, I’ll turn the call over to Jeff Agosta for the financial review and outlook. Jeff?
Thanks, Dave and good morning everyone. Today I will take you through a brief review of our financials and operating results for 2012 and provide commentary on our outlook for 2013. Starting first with production, in the fourth quarter we produced 62.4 million oil equivalent barrels or 679,000 BOE per day. This result was at the high end of the guidance we provided last quarter. This strong performance was driven by excellent execution in our core development regions.
In the fourth quarter, companywide oil production averaged 151,000 barrels per day, a 6% increase compared to the previous quarter and an all-time high for our North American onshore asset base. Looking ahead to the first quarter, we expect our strong oil growth to continue. Led by increased activity levels in the Permian basin and Mississippian, we are forecasting first quarter oil production to average between 153,000 and 163,000 barrels per day.
Overall, we expect total companywide production of oil, gas, and NGLs to total about 670,000 BOE per day in the first quarter of 2013, down slightly from Q4. This is a result of a sequential quarter growth in oil and liquids production, being more than offset by a 5% decrease in gas production. The quarter-over-quarter decrease in gas production reflects the timing of well completions and is not indicative of the decline rate in gas we expect for the full year.
Now for a brief review of our revenues. In the fourth quarter, E&P revenues increased 8% over the previous quarter to $1.9 billion. Significantly higher natural gas price realizations during the quarter drove this result, more than offsetting the weak oil pricing received on our Canadian production.
Fourth quarter Canadian oil realizations came in at 59% of the WTI benchmark or about 5 percentage points below the low end of our forecasted range. The most significant factor that impacted fourth quarter Canadian oil prices was high crude storage levels resulting from unexpected third-party pipeline curtailments in November and December.
Looking ahead to the first half of this year, these high inventory levels, coupled with downtime at multiple refineries and restricted flow rates on export pipelines, will continue to impact Canadian crude prices. However, we believe that the supply and demand dynamics related to Canadian crude will significantly improve in the back half of the year.
A key demand catalyst currently expected to occur in the second half of year is the startup of the Whiting Refinery. This will bring on 260,000 barrels per day of incremental heavy crude processing capacity. Additionally, as 2013 progresses, we expect increases in pipeline and rail capacity will help alleviate transportation bottlenecks. We believe these favorable developments will improve our Canadian oil realizations for the second half of the year.
We are also experiencing wide oil price differentials in the Permian. A delay in the startup of the Longhorn Pipeline that will move oil from West Texas to the Gulf Coast is negatively impacting realizations in the first quarter. However, the good news is that we expect the Longhorn Pipeline in the West Texas Gulf expansion to be operational early in the second quarter, adding almost 300,000 barrels per day of takeaway capacity to the Gulf Coast. This should cause our differentials in the final three quarters of the year for the Permian to shrink to more historical levels of roughly $1 to $3 discount to WTI.
Looking briefly at the impact of hedges, in the fourth quarter, our hedge position delivered cash settlements of $202 million. In total, these settlements enhanced our companywide average realized prices by $3.24 per BOE, an uplift of 11%. For 2013, through a combination of swaps and collars, we have roughly 70% of our forecasted oil production locked in with a weighted average floor price of $96 per barrel. We also have about 60% of our expected gas production for the year hedged at a weighted average protected price of $3.87. In the 8-K we are filing later today, we will provide a more detailed breakdown of both our hedging positions and our expected price realizations.
Turning briefly to our midstream business. Driven by improved gas prices and strong cost management efforts, our fourth quarter operating profit climbed to $121 million, bringing our full year midstream profit up to $410 million. Looking ahead, we expect improved gas prices and increased processing capacity in the Barnett and Cana to increase profitability this year. For 2013, we are forecasting our operating profit to range from $425 million to $475 million, with the first quarter expected to range between $100 million and $120 million.
Moving to expenses. Our fourth quarter cash expenses were generally in line with our expectations with total pre-tax cash costs coming in at $15.20 per BOE. The only outlier versus guidance was G&A expense coming in at $198 million or $3.17 per BOE. This was about $25 million above the top end of our forecast. A $21 million charge related to the early settlement of pension liabilities was the biggest driver. Even with this un-forecasted expense in the quarter, Devon maintains a best quartile cost structure in the E&P industry. This is especially noteworthy given our shift to oilier projects which have higher margins but are generally more expensive to produce. Cutting to the bottom line, as Vince mentioned earlier, our non-GAAP earnings were $0.78 per share, $0.03 higher than the Street's mean estimate. This level of earnings translated into cash flow per share of $3.11, exceeding the consensus expectations by 12%.
Now for a quick review of our financial position. For 2012, Devon's cash flow from operations totaled $5 billion. Combined with the joint venture proceeds and other minor asset sales, our total cash inflows reached $6.5 billion for the year. This cash allowed us to comfortably fund a robust capital program while maintaining excellent financial strength. At December 31, our cash and short-term investments totaled $7 billion and our net debt to adjusted cap ratio was only 18%. While we clearly possess a great deal of financial strength and flexibility, we are fully committed to exercising capital discipline, maximizing our margins, maintaining our balance sheet strength, and optimizing our growth and cash flow per share adjusted for the debt.
So with that, I'll turn the call back over to Vince for the Q&A. Vince?
Operator, we're ready for the first question.
(Operator Instructions) Our first question comes from the line of Dave Kistler with Simmons & Company. Your line is open.
David Kistler - Simmons & Company
Real quickly, thinking about the pursuit of maybe MLP-ing the midstream, obviously bringing another significant amount of capital on top of the $7 billion you already have, realize that $7 billion you're waiting on repatriation thoughts around that. But with that kind of a war chest, should we be thinking towards potential acquisitions going forward or is that still probably off the table?
Well, first of all -- Dave, this is Jeff. If we do a MLP IPO, the initial proceeds from that would generally be in the $300 million to $500 million range. So it would not substantially increase our cash position. And we're continuing to study the impact of repatriating the cash that's offshore. We have about, just for reference, we have about $6.5 billion of our $7 billion in cash is outside of the United States. The remaining $0.5 billion is in the United States. So, I'll turn the rest of the answer over to John.
So, Dave, as Jeff says, this comes in tranches, when you do something like this, right. So you get the value out over time. So it does increase it. Look, anything that we do – first of all, we’ve got a lot of projects that Dave has been talking about that are oil projects that if they’re successful as we think they’re going to be, they’re going to require quite a bit of cash investment over the next few years as we develop them into really major projects. But anything that we do, whether we're investing that money in our projects, whether we use it do an acquisition, whether we buy back stock, we’re going to do whatever is going to result in the most accretion and cash flow per share adjusted for debt. We've talked a lot about that metric. We think that that ultimately is what we ought to be focused on. So nothing is off the table.
David Kistler - Simmons & Company
I appreciate that. And then maybe jumping into one of the specific oil projects. You mentioned variability of results in the Cline. Can you guys give us some additional color on what you think – I know it's early stages – could be driving that variability of results and then I'll let somebody else hop on.
Sure, Dave. This is Dave Hager. Yeah, I think there are two big factors that – well, I'd say three. I guess one, geographic where we are testing various areas throughout our acreage position. Second is landing zones. We are still testing out various landing zones within the Cline and other formations to see what may be the best. And third, completion techniques and we're still optimizing the completion techniques. So it's just really early on in the play to give any sort of conclusive results. But I can tell you we're optimistic with what we're seeing so far and we're very confident we're going to make this into an economic play.
Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Your line is open.
Doug Leggate – Bank of America Merrill Lynch
I have a couple of questions, one on the MLP and one on the Miss, if I may. John, one of the things that you talked about in the past about reasons for not doing an MLP was the variability of the NGL component of your earnings and a very low tax basis. Can you help us understand what's changed on those two issues? And my follow-up is on Miss, please.
Well, a couple of things have changed, Doug. You're right. I mean, when we looked at it before, that was a bit of a stumbling block, because an MLP with high variability or high exposure to commodity prices did not exact the same kind of multiples as say a tolling business did. We've talked a lot about that in the past. There are a couple of things that have changed. First of all, we think there may be more of an opportunity for us to change the nature of some of the contracts that we have today than a few years ago for a variety of contractual reasons. And secondly, there are some innovations, if I can call it that, that have arisen in the last few years as where the operating company can ensure a more constant cash flow through hedging or other techniques with the – between the MLP and the operating company, and where the operating company becomes the counterparty.
So there are some new ideas around that that have arisen that we think are ones that we need to look at pretty carefully. Of course there's a transfer risk when you do that as well and that has to be factored into the equation. But those are the kinds of things that we can do or we can – you're always going to have a little bit of variability. This is not going to be a tolling business. So we can take the wide variability out that we have our portfolio exposed to percentage of production type contract.
Doug Leggate – Bank of America Merrill Lynch
And on the tax, John?
Doug, this is Jeff. The tax basis hasn't really changed. That situation still exists and so we would just need to be thoughtful and deliberate about how we move the assets into the MLP to minimize the tax leakage.
But we have and we are adding new assets all the time and to the extent we have newer assets, then gosh, we talked today about this even, it's not out of the question. You could do some of this with the Canadian assets. We're building the Ferrier plant. We're building out facilities in the Miss. We're building out facilities in the Permian. All of those things would have a much higher tax basis as well if we were to start doing drop-downs over time.
Doug Leggate – Bank of America Merrill Lynch
Got it. Thank you. My follow-up, I guess this is probably for Dave. But Dave, the Vitruvian acreage that you picked up in the northern part of the Miss, assumingly Dave it all seemed – it was in a better area I guess than the joint venture acreage. Do you have any obligations or any agreements forthcoming between yourselves and Sinopec in terms of how you might involve them in that and maybe talk a little bit about the relative EUR prospectivity of that area relative to the Southern piece? And I'll leave it there. Thanks.
Yeah. There are no obligations with Sinopec regarding how we develop the acreage outside the existing joint venture area with Sinopec in the Mississippian. So we can develop that as we deem appropriate out there. It's still early on, I would say overall, Doug, to get an idea of the EURs outside to the North there, and what you're calling the Vitruvian acreage versus inside the joint venture area with Sinopec. We really need to get more well completions on line. We're encouraged with what we've seen so far, and of course there are a lot of wells immediately to the west of that that a couple of our competitor companies have drilled.
We think we're going to be able to even improve on those results because we're going to use 3D seismic to optimize the results. We're going to have an integrated petrophysical model that we're going to use. And so it's a more geo-science intensity approach that we're going to use. And so, we think over time, once we get all that data and put all that together, we're going to see even better results. But we don't have that much results to-date with our own wells to be able to say conclusively at this point whether that's true. But we certainly believe that's going to be the case.
Our next question comes from Bob Brackett with Bernstein Research. Your line is open.
Bob Brackett - Bernstein Research
You mentioned de-booking some liquid rich reserves. I'm wondering where those reserves were located.
Essentially, any gas projects with lower gas prices the economic tail is shortened, and so that would be really across our liquids-rich positions. And we had minor of negative revisions associated with Cana where we've talked about in the previous call, where we went to a reduced frac size with our 2011 program and we had a minor amount of negative reserve revision associated with that which were liquid rich. But it's very minor in the overall scheme.
Next we have the line of Brian Singer with Goldman Sachs. Your line is open.
Brian Singer - Goldman Sachs
When you think about the U.S. E&P business on a standalone basis, do you believe you have the assets at this point where that business can stand on its own without either JV proceeds or carries? Or do they need either acquisitions or the growth and cash flow synergies provided by your Canada business?
Brian, a few things. First of all, our Permian position is about as good a position as you get in this industry. We've got over 1 million acres in the Permian. We're growing that at 30s and 40s percent. I mean, that's growing very well. And we've added these new areas. Now, we're in the early stages of a couple of areas, the Cline, of course, and the Mississippian. But we are encouraged by it and we've got the acreage position that makes sense for a company our size, where you can get the scale and the efficiency. So, it's not a slam-dunk for us obviously because it's early days in some of these plays, but we've added some very good positions.
We are also encouraged by what we're seeing in the Rockies. We started talking about that as the Niobrara, and now we're seeing a lot of other formations, but it's a multi-zoned area that we are continuing to pursue as well. But I think there's still some work to do obviously for us to fully understand it, but we think that we have put together some pretty prospective areas that really supplement this tremendous growth that we're going to see for many years in the Permian. And if gas prices start to change, if NGL prices start to come back, we think we've got some really good projects where we have the scale and the efficiencies and the infrastructure to grow them very effectively.
I might just add. Really the assets that we have in place right now are totally sufficient for growth for the next couple of years. There's no question about that. I think the question is beyond that, how large scale are the Mississippian or Cline positions. And what we've seen so far is very optimistic. But there's no issue for the next couple of years whether we have plenty and we are taking the exploration risk associated with it out by doing these joint ventures. And then once they get to full or large scale development, then they can really impact us materially. And so we are very optimistic at this point. We still need some more results but the early results are very encouraging.
And Brian, one last comment. As you know, we've got a dedicated new ventures team that's looking at new opportunities all the time. So those things – again as Dave said, that's development for the future, but those things are continuing as well.
Brian Singer - Goldman Sachs
That’s great. And then as a follow-up, just looking at your production guidance that you talked about earlier, I think the crux of that is the oil growth in the U.S. and it seems to be about 17,000 or so barrel a day increase from your fourth quarter levels. Can you just provide a little more granularity about – is that almost entirely driven by the Permian or a little bit more granularity on whether the Mississippi Lime or some of the areas in the Rockies are providing contributions to that?
It is primarily driven by the Permian with some minor contributions early on here with the Mississippian and in the Rockies. But the biggest part of it is the Permian.
Next we have David Tameron with Wells Fargo. Your line is open.
David Tameron – Wells Fargo
Question on use of proceeds for cash. I know we've talked about in the past a little bit, but how you guys look at your current dividend policy and could we anticipate any changes there?
Yeah. David, as you probably know, we've increased our dividend every year since its inception, except during the height of the financial crisis and while we were doing our redevelopment – or repositioning of the company. So we've had an intention and a history of increasing every year. We tend to look at that in around March of the year. We'll take it to our Board of Directors again this year and we have every reason to believe we'd be continuing the increase. But we think what's really important is to have a sustainable dividend and one that we can regularly increase over time.
David Tameron – Wells Fargo
Okay. But as far as many meaningful changes, you don't anticipate that at this time. Is that what I'm hearing, John?
Well, I guess it depends on what you think meaningful is. I guess we think we're going to continue to increase it.
David Tameron – Wells Fargo
Okay and then as a follow-up just on a completely separate topic. Your production guidance, can you talk about what assumption you've made as far as ethane recovery or rejection and how that could swing your full-year production number?
Well, at this point we're probably being impacted on the order of about 3,000 barrels a day or so by ethane rejection currently. At this point we’re not rejecting ethane on our current Devon operated plants. The full impact if it would – if we would make that decision, which of course we'll evaluate continuously throughout the year, we're probably on the order of 10,000 to 50,000 barrels a day if we made that decision.
David Tameron – Wells Fargo
Okay. And just to clarify, is that in your guidance or is that not in your guidance?
It is not in our guidance right now that we will reject ethane beyond the 3,000 barrels a day that is currently happening on our outside operated projects.
This is Vince. I might add that we have some of the lowest transportation costs and our participation in the extraction business gives us really some of the best ethane extraction economics of the industry. So our point at which we reject isn't necessarily equal to that of our figures.
Next we have the line of John Herrlin with Societe Generale. Your line is open.
John Herrlin – Societe Generale
Not to beat a dead horse with the MLP, but you almost went through the process once before. Gas prices have been weak a while. Is this just a preempted move? Because you're really not short of cash, so why bother doing it?
Well, John, yeah, gas prices have been lower, but those things change over time and these MLPs take a while to fully develop as well. So the price at any point in time, I'm not sure is the right way for us to look at it. And whether our – wherever prices are, I mean we ought to always be looking at and we try to always look at ways to unlock value in the company. We think this is just one of the ways that we can do that and market conditions are such that it makes it much more attractive than when we did that before. And as I was saying, today capital markets are much deeper. The yields have all changed. Some of the innovations with regard to structuring make it more attractive. The fact that we're out there building new facilities all the time to create a continuous stream of dropdowns for an MLP, make it all attractive for us. So we think it's the right thing to do irrespective of either where the commodity prices are right now or where stock prices are right now.
John Herrlin – Societe Generale
Okay. Thank you, John. One for Dave. Could you see, Dave, in the Permian a whole lot more capital being allocated to the plays and could you rank them in order of priority?
Sure John. First off, we have ramped up our activity significantly in 2013 over 2012, and of course '12 was up significantly over '11. So we have been increasing a lot. We're going to spend about $1.5 billion there amongst four different plays really, the Bone Springs and Delaware, lumping them into one. Wolfcamp, Cline Shale, second, Wolfberry, and then up on the Central Basin platform. There's different ways to rank them, John, I guess you'd say, if you look at current economics I'd say the Bone Springs and Delaware probably rank at the top of the list. If you look at total resource potential then certainly the Cline Shale and the Wolfcamp Shale would rank at the top of the list. And as we really drive the economic value as we move forward in the Cline Shale, it could be very, very significant.
Now, can we do more in the future than we're doing right now, I think we are continually looking at ways to increase our activity even further, because these are very strong economics. There are infrastructure limitations as far as gas takeaway capacity and you can't – you can’t take the gas away. So if we can't take the gas oil, you have limits on your oil production there, you have that issue. We have internal constraints for manpower, there is getting the permits from the state and the feds. So that's a process. We're addressing all of those issues currently and we're looking at ways to increase even further. There's also just the pace of geologic maturity of the prospects also and we can't get too risky out there on that side. But we're working on all that, John, because we recognize that these are strong economics and we have a premier position in the industry out here.
All right. Operator, I'm showing the top of the hour so we'll end today's call. As usual, we'll be around the rest of the day to take any questions that didn't make it into the call today. Thank you for your participation.
This concludes today's conference call. You may now disconnect.
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