Jeffrey L. Mobley - Senior Vice President of Investor Relations & Research Aubrey K. McClendon - Co-Founder, Chairman, Chief Executive Officer and Chairman of Employee Compensation & Benefits Committee Domenic J. Dell’Osso - Chief Financial Officer and Executive Vice President Steven C. Dixon - Chief Operating Officer, Executive Vice President of Operations & Geoscience and Member of Employee Compensation & Benefits Committee

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division David W. Kistler - Simmons & Company International, Research Division Jeffrey W. Robertson - Barclays Capital, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Marshall H. Carver - Capital One Southcoast, Inc., Research Division Biju Z. Perincheril - Jefferies & Company, Inc., Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Joseph D. Allman - JP Morgan Chase & Co, Research Division

Good day, and welcome to the Chesapeake Energy 2011 Fourth Quarter Earnings Results Conference Call. Today's conference is being recorded. At this time, I'd like to turn the conference over to Jeff Mobley. Please go ahead, sir. Jeffrey L. Mobley: Good morning, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2011 fourth quarter and full year. I would like to begin by directing your attention to the slide presentation available on our website that we will refer to in our prepared remarks this morning. The slides can be accessed at www.chk.com, then selecting the Investor tab near the top of the page, followed by the Presentations section in the menu bar. I would next like to introduce the other members of our management team who are with me today on the call: Aubrey McClendon, our Chief Executive Officer; Steve Dixon, our Chief Operating Officer; Nick Dell'Osso, our Chief Financial Officer; and John Kilgallon, our Director of Investor Relations and Research. Our prepared comments today will be a bit longer than our typical call as we have added additional detail on our operational performance that will be highlighted by Steven Dixon. We will then move to Q&A. I'd now like to turn the call over to Aubrey. Aubrey K. McClendon: Thank you, Jeff, and good morning. We are very pleased with our company's operational and financial performance during 2011. Here are a few highlights to consider when analyzing our performance for the year. Turning to Slide #2. For the full year, we increased our production by 26% before asset sales and 15% after asset sales. Chesapeake remains the largest gas producer in the U.S. on a gross basis and the second largest on a net basis. More importantly, we moved up to the 11th largest oil producer in the U.S. during 2011 from the 15th largest in 2010 and from the 21st largest in 2009. We increased our proved reserves by 26% before asset sales and 10% after asset sales. And we now have proved reserves of approximately 19 Tcfe or the equivalent of 3.1 billion barrels of proved reserves. We found through the drillbit a remarkable 5.6 Tcfe of proved reserves at the very low drilling and completion cost of only $1.08 per Mcfe. Stated on a BOE basis, we found almost 1 billion barrels of oil organically. These results are unmatched in the industry and form the core of our ability to continue creating shareholder net asset value every year of at least $10 billion. Chesapeake's risk unproved resources are now in excess of 110 Tcfe. And between our proved reserves and unproved resources, we control more oil and natural gas resources in the U.S. than any other company. Based on our present market valuation, this unproved resource base is quite amazingly available free of cost to our investors. During 2011, our net long-term debt on an absolute basis declined by 18% and on a relative basis, which includes benefit of the growth of our proved reserves base, net debt for proved reserves declined by 25%. Further, we believe approximately $1 billion of our total long-term debt should be reasonably allocated through our midstream and oilfield service businesses. After this allocation, our E&P debt is only $0.49 per proved Mcfe, which is clearly an investment-grade metric and is in fact, lower than at least one of our investment-grade rated peers. We are focusing on creating per share value for our investors, and so we are proud to deliver strong operational and financial performance without incremental equity from the public markets. During 2011, our fully diluted share count increased by only 0.6%, which is solely related to employee stock compensation. I believe we still remain the only large cap E&P company that distributes restricted stock to virtually all of its employees, in our case today, nearly 13,000 people. I believe this practice at least partially accounts for the hardworking, creative and motivated organization that we have built. Speaking of which, on Slide #3, I am proud to highlight that recently, Chesapeake was named by FORTUNE Magazine as the 18th Best Company to Work For in the U.S., including the fifth best among companies with more than 10,000 employees. In addition, we were #1 among all companies in the oil and gas business. This is our fifth consecutive year on this prestigious list, and we have moved up from #61 to #18 in those 5 years. I would also like to mention that our fellow Oklahoma City producer Devon is ranked #28th on the list. That means that of the more than 400 publicly listed oil and gas producers in the U.S., only 3 made the top 100 Best Companies to Work For, and 2 of those 3 are located right here in Oklahoma City, a very noteworthy achievement for our community. Turning to Slide #4. During 2011, we sold assets for $8.5 billion, reaping pretax economic gains of $5.6 billion from those sales, or a profit margin of approximately 65%. Please note, however, that because of the conservatism of full cost accounting, only $437 million of those gains appeared on our income statement. On a percentage basis, our liquids production increased by 72% in 2011 versus 2010. This is the second-best track record of oil production growth in the industry on a relative basis. On an absolute basis, our liquids production increased by 36,000 barrels per day, also the second-best performance in the industry. Further impressive liquids production growth lies ahead for Chesapeake. For 2012, we believe our liquids production will increase by more than 70% or approximately 63,000 barrels per day compared to 2011. We remain convinced that Chesapeake will become a top 5 producer of liquids in the U.S. by 2015, with more than 250,000 barrels per day of liquids production. Moreover, on Slide 5, we announced our 25/25 Plan in January 2011 that stated we would reduce our net long-term debt by 25% and increase our production by 25% during 2011 and '12. I'm pleased to report that during 2011, we achieved 72% of our debt reduction target and 60% of our original production growth target. With regard to unproved leasehold, always a popular topic among observers of our company, we invested $3.5 billion during the year and collected $4.4 billion in sales of unproved leasehold, resulting in a net cash unproven leasehold inflow of $900 million. At the beginning of the year, I committed that our undeveloped leasehold sales would be at least equal to our undeveloped leasehold acquisitions during 2011. As you can see, I was off by $900 million, but off to the good side. I further commit that in 2012 and 2013, we will also likely generate more cash from undeveloped leasehold sales than we will spend in undeveloped leasehold. Please keep in mind that these numbers are cash-only and excludes the benefit of drilling carries that we receive when we sell portions of our undeveloped leasehold. If we included carries in our calculation of the leasehold sales, these numbers would obviously look even better. The final takeaway, I think, on leasehold investment should be this: Whatever we spend on leasehold acquisitions in a given year, we will more than offset it from undeveloped leasehold sales. How are we able to continue doing this, you might ask? It's actually quite simple. Chesapeake is the best in the industry at finding new unconventional plays, acquiring big leasehold positions in the heart of the plays, and then selling off a minority interest to a bigger company from elsewhere in the world that cannot do what we do but has access to capital that we do not have. These are truly symbiotic relationships that benefit both companies, and I'm proud to say that Chesapeake was the first to recognize this extraordinary business opportunity back in 2008. Today, we have -- to date, we have entered into 7 JVs that have generated $7.1 billion in cash from undeveloped leasehold sales and $9 billion from drilling carries for a total value generated of $16.1 billion. Our cost basis in the assets sold was only $3.8 billion. That's an economic profit of $12.3 billion or more than a 3:1 return. However, again, due to the conservatism of full cost accounting, none of these gains are presented in our income statement. Turning to Slide 6. During 2011, we were the first company to establish commercial production from the Utica Shale, the first big new shale play since the Eagle Ford was developed -- discovered in 2008. We're very excited about the Utica, our results to date and its future potential. Steve Dixon will have some new well results for you from the Utica in a few minutes. To date, we have invested approximately $2.2 billion in the play and have sold off roughly 20% of our leasehold for a total cash and carry value of about $2.3 billion. Said another way, we recovered 105% of our cost to date and yet still have 80% of our acreage left. That's exceptional under any circumstances, but especially when you consider that Chesapeake's average holding period in its Utica leases is only about 1 year. On Slide 7, I wanted to point out that in 2011, we generated gains of $437 million from a drop-down transaction with our midstream affiliate, CHKM, that trades on the New York Stock Exchange. Please remember that most of our peer companies, unlike CHK, failed to capture midstream profits for their shareholders. We believe this is a very key element as to why Chesapeake's integrated business strategy is a superior business model. Also during 2011, we formed COS, that's Chesapeake Oilfield Services, a company that holds our various oilfield service businesses. Inside of COS, we own the nation's fourth largest drilling contractor, the nation's largest oilfield trucking company, one of the nation's largest oilfield tool rental businesses. And we are also building under the name of Petroleum (sic) [Performance] Technologies Limited, or PTL, what will become a top 5 fracture stimulation company. We now have 2 PTL frac crews in the field. And by the end of 2012, we will have a total of 8 frac crews active. And by the end of 2013, we will have a total of 12 crews in the field. We believe that by having Chesapeake's own in-house frac-ing capability, it leads to greater efficiencies and lower costs. We believe COS will make an excellent candidate for an IPO later this year, and it is another example of the benefits of Chesapeake's vertically integrated business strategy. Also in the service industry, with strong support from Temasek and RRJ Capital, we helped to recapitalize Frac Tech Services in 2011, which is today the fourth largest fracture stimulation company in the U.S. We own 30% of this fine company and have a cost-based incentive of only $100 million. Meaning, we have an embedded profit that will likely exceed $1 billion. Slide #8 shows that our commodity hedging program generated strong gain again this year. After our gains of $1.6 billion in 2011, we have now generated $8.4 billion of hedging gains in just the past 5 years, by far the best track record of hedging success in the industry. And finally, even in the face of sharply lower natural gas prices, our 2011 adjusted EBITDA and cash flow increased by 6% and 3% compared to 2010's numbers. We think this is a pretty extraordinary achievement given what happened to natural gas prices in 2011. On Slide 9, during the year, we also continued our industry-leading effort to increase demand for natural gas. One such project was to help lead $400 million of investments through multiple transactions in Clean Energy Fuels, stock symbol CLNE on the New York Stock Exchange. Clean Energy is the nation's largest provider of natural gas and to transportation fuel, and they have a very strong momentum in building out the infrastructure for America's natural gas super highway. I can assure you that the move is underway to move the nation's transportation sector increasingly away from imported diesel and gasoline towards domestically produced and much cheaper natural gas. You might also take note of yesterday's press release in which the 3M Company and Chesapeake agreed to jointly deliver a breakthrough in CNG fuel tank technology that will help lower the cost of natural gas vehicles. Also for the benefit of our entire industry, we have curtailed approximately 15% of our gross operated production or approximately 1 Bcf per day. Our share of this curtailed gas is about 50%. This is, of course, far more than anyone else in the industry has announced, and we think it speaks volumes about Chesapeake's financial flexibility and operational strength that we can make this sacrifice and still reach all of our objectives for the year. On Slide #10, the most important element of our ongoing success is Chesapeake's very high asset quality. I'm proud to report that Chesapeake now owns the largest or second-largest positions in the following 15 leading U.S. unconventional plays. Starting first with gas shale plays: we are #1 in the Haynesville; #1 in the Bossier; #1 in the Marcellus; and #2 in the Barnett. Moving to liquids-rich plays: we are #1 in the Utica; #2 in the Eagle Ford Shale; #1 in the Cleveland tight sands; #1 in the Tonkawa tight sands; #1 in the core area of the Granite Wash; #1 in the Mississippi Lime; and #1 in the Powder River Basin, Niobrara Shale. And in the Permian Basin, we believe our overall acreage position of 1.5 million net acres is tied for the second largest in the basin. In this largest oil-producing basin in the U.S. and arguably the hottest basin in the world, we have leading positions in the Wolfcamp, Avalon, Bone Spring and Wolfberry plays. So even if we were to sell 100% of our Permian Basin assets, Chesapeake would still retain a #1 or #2 position in 11 of the nation's best gas and liquids-rich plays. We're not aware of any other company that can claim more than 2 or 3 of such positions. Reviewing this extraordinarily high-quality lineup of assets, it should be no surprise to you that Chesapeake has single-handedly generated 30% of all the natural gas production growth in the U.S. during the past 5 years. It should also help explain how we have increased our liquids production by 170% in the past 2 years and how we intend to increase it by a further 190% in the next 4 years. As a result, we believe Chesapeake will likely turn in the best liquids production growth performance in the U.S. and one of the best in the world during the next few years. On Slide 11, we entered 2012 with a strong momentum and sound business strategy to continue making the shift from a 90% natural gas producer in 2009 to a much more balanced producer in the years ahead. However, we acknowledge that this shift away from gas to oil has required us to outspend our cash flow, and we also acknowledge this is causing anxiety among some investors and observers of our company. However, with our detailed announcement on February 13, we have now clearly articulated a strong plan of action that should enable us to generate $10 billion to $12 billion of proceeds from asset monetizations this year, that when combined with our operating cash flow will easily fund the gap between our operating cash flow and our capital expenditure on our spending for the year. It will also probably prefund any gap in 2013 as well, which will be much smaller, by the way, than this year's gap, as natural gas prices will likely increase, as supply growth wanes and demand growth comes on strong. More importantly, Chesapeake's production mix will continue to tilt towards more liquids production, and therefore, will generate more revenue per unit of production. By 2014, we are confident the company will reach breakeven between its operating cash flow and capital expenditures, even if natural gas prices remain at depressed levels, which given the rapidly changing supply and demand fundamentals emerging in real time before us today, we think is very unlikely. However, despite the obvious very good place where we are headed with our surging liquids production and despite the obvious very bad place we would be if we'd simply stayed within our cash flow and remain a 90% natural gas producer, I still read a surprisingly large amount of analyst commentary that remains singularly, and in my opinion, unimaginatively focused on how much CapEx we have spent. Our job as the management stewards of shareholders' capital is to create the highest amount per share of net asset value possible within our overall financial capabilities. That is why we focus on the outputs of our business, while it seems other people seem to obsess over the inputs to our business. But it is not the inputs that matter at the end of the day, it is the outputs. And our outputs are not only increasing in size, but also increasing in value on a per unit of production basis. And by achieving this quite remarkable and utterly complete transformation of our company in just 3 years, we will arrive at a place in 2014 when we are cash flow-positive and to a place in 2015 when our cash flow should be $10 billion to $11 billion and our company will be valued at several multiples higher than our total enterprise value to date. This will create enormous value for our shareholders in the next few years. Again, if inputs were the only thing that mattered, then we would live today within our cash flow and sit here and hope and pray for higher natural gas prices. But it is indeed outputs that matter, and so that's what our focus is on, to increase those outputs and total volumes and to increase the per unit value of those assets, or outputs rather, while at the same time delevering the company by 25% on an absolute basis and close to 40% on a relative basis in just 2 years. And by the way, we will get all this done in an environment of sub $3 natural gas prices. It's not easy, and I read that several analysts this morning are skeptical about our ability to achieve this transformation. But their skepticism will not be rewarded at the end of the day, while indeed our shareholders will be greatly rewarded. I'll now turn the call over to Nick for his further comments about the company's financial performance. Domenic J. Dell’Osso: Thanks, Aubrey. It's been an exciting start to 2012, and we're very pleased about where we're headed. First, to cover our Q4 and full year results, I'd like to point to our $2.80 per share in EPS, driven by production growth and cost control. Our LOE for the fourth quarter came in at $0.88 per Mcfe, a decrease of $0.02 per Mcfe over Q4 2010. In addition, current year LOE includes approximately $0.11 per Mcfe from the effects of VPPs. This is evidence of some of the efficiencies we've been able to create within the country's largest drilling program and vertically integrated model. We do expect this metric to tick up a bit in the future as producing oil and NGLs is more expensive. However, we're quite proud of the base from which we will grow and we'll continue to take advantage of our model to deliver a best-in-class cost structure. From a balance sheet perspective, our production and year-end debt balance show great progress towards our 25/25 Plan. One quick note I'd like to add to the previous comments on our production growth target moving back to the original 25% level as a result of our curtailment decision is that in our outlook on Schedule A of our earnings release, we note a total assumed curtailment of 130 Bcfe during 2012. If we had chosen to produce the curtailed volumes, we would have achieved an additional 13% production growth or 38% -- total of 38% production growth in 2010, a remarkable level for a company of our size. We will certainly be poised to take advantage of rebounding gas prices when they occur. It's been our strategy to continue executing on 2 of our primary goals in 2012, increasing oil and liquids production and decreasing our financial leverage. We made the decision to stay the course on these goals even in the face of low natural gas prices, as we feel achieving a balance in our production profile and decreasing leverage are key to growing long-term shareholder value. As a result, as Aubrey mentioned earlier, we have been playing to outspend our operating cash flow this year. We were pleased to provide more transparency on how we plan to do that last week with our announcement regarding significant asset sales and other monetizations we plan to pursue in 2012 and hope that the table at the bottom of our 2012, 2013 outlook makes all of our investing activities for the year very clear to you. This summary of cash inflows and outflows should highlight that we have given ourselves quite a bit of headroom in 2012. And inclusive of that carryover, we'll have quite a bit in 2013 as well. To clarify a few things you read last night and this morning, we have made very little material changes to CapEx and only tried to provide more detail and transparency through the view on what is being spent and what is being monetized. We, of course, have been working on these monetizations announced last week for quite sometime and always maintained a good amount of optionality on how we think about funding our business, given our asset-heavy business model. Our diversity of assets, which include proved reserves, natural gas and oil production, large acreage positions and vertically integrated midstream and service company investments, provide a variety of assets from which there are many different buyers that find attractive assets within our portfolio. Great examples of the variety of assets we choose to monetize to buyers seeking different return profiles are: our Colony Granite Wash royalty trust, where primarily retail investors receive an income stream tied to the specific production of a certain field; and our Utica wet gas JV, where an international major took a significant exposure to a largely undeveloped play in Ohio with tremendous upside exposure. Further, in the outlook on our press release today, I'll point out that we have lowered our gas price forecast to more closely match the strip and now project 2012 operating cash flow before changes in working capital to be $4.85 billion at the midpoint of our range. Please remember that approximately 60% of our revenue in 2012 will come from oil and natural gas liquids at the prices modeled here and we hedged 43% of that production at approximately $102.50 per barrel. Also, please note that our operating cash flow projections are expected to increase by 65% in 2013 versus 2012. If you look at Slide 15 in this morning's presentation, you'll see that even if prices were to remain flat, our cash flow will jump by 35%. That's very exciting growth and really highlights the benefits of our shift to liquids-focused assets and the return we are seeing on our investment in liquids-rich acreage positions for the last several years. With that, I'll turn the call over to Steve to give an overview of some of our recent significant operational achievements. Steven C. Dixon: Thanks, Nick. Moving onto Slide 18. 2011 marked another outstanding year for Chesapeake operationally. I'm very proud of the results in 2011 for our entire team as we continued our best-in-class performance and in reserves and production at very low cost while maintaining our high standard for safety and a keen focus on environmental stewardship. During 2011, we produced nearly 1.2 Tcfe on a net basis and increased our gross operated production to 6.4 Bcf per day. We finished the year with 18.8 Tcfe of proved reserves based on SEC pricing, and that's after sales of 2.8 Tcfe of proved reserves, primarily from our Fayetteville Shale transaction with BHP. Our operational teams performed exceptionally well during a rising oilfield service cost environment in 2011. And we delivered 5.6 Tcfe in proved reserve additions due to drillbit at a drilling completion cost of only $1.08 per Mcfe or approximately $6.50 per BOE. Notably, our reserve additions in just that 1 year of 2011 exceeded the total proved reserves of all but just a handful of our competitors, many of which have been in operation for more than 20 years. As an operator, we drove a total of 1,680 gross wells and connected more than 1,400 wells, or about 1 every 6 hours, and substantially all of these were horizontal wells. This is an unprecedented level of activity, a performance the industry has never seen before. We also participated in another 1,250 wells drilled by others, and those operators turned 1,050 wells online during the year. Slide 19 shows, in executing its business, Chesapeake enjoys tremendous competitive advantages through the size and scale but also by utilizing the largest data set in the industry that benefits from the most active drilling program in America, the largest U.S. leasehold position and a unique ability to evaluate technical and petrophysical data in our Reservoir Technology Center that has analyzed more feet of shale cores since its opening in April 2007 than the rest of the industry combined. Our company has developed key abilities in new play identification, leasehold acquisition, large-scale drilling and completion programs, where we have ramped up to 20, 30, even 40 rigs in a single play. Our operations are further enhanced by our vertical integration into oilfield service and midstream operations. Our goal in the end is to conduct our operations better, faster, cheaper and safer than our competition so that we can lead the industry at a per share net asset value creation. As a result, Chesapeake has clearly become the partner of choice for many international companies seeking access with the lucrative low-risk U.S. onshore natural gas and liquids plays. And we look forward to completing additional partnerships and transactions later this year. I'd next like to highlight a few operational results in some of our key liquids-rich plays. On Slide 19 in our Eagle Ford Shale play, our total net production averaged over 17,700 BOE per day in 2011's fourth quarter. That's up 60% versus last quarter and 370% year-over-year. Our current gross operated production from the play is 45,500 BOE per day and 22,600 BOE per day on a net basis. Our production mix in this play is approximately 50% crude, 20% NGLs and 30% natural gas. We continue to be very pleased by our performance in the Eagle Ford, and it's a driving force behind our liquids production growth targets in the months and years ahead. To date, we have 108 wells that tested with peak oil rates of 500 barrels of oil or more. And that's not an equivalent basis, that's black oil in the tanks. We are producing 178 wells in the play to date and have a backlog of almost 200 additional wells to be completed and connected in the coming months. This will fuel our production ramp-up through the end of the year and into '13. We finished 2011 with 7 frac crews running in the play and will be up to 11 by mid-March of this year and 13 by the end of 2012. We've also doubled our drilling efficiency in the play since January 2010 based upon drilling feet per day to now approximately 725 feet per day. And this has driven down our days per [ph] wells and helped reduce costs. And great progress has been made in building and restructuring the play with the addition of 350 miles of pipeline during the year. We expect to gain greater transportation capacity as 80 more miles of pipeline and regional rail and loading terminals are put in. And we also are adding 85 oil hauling trucks from Chesapeake's very own trucking company within Thunder Oilfield Services. These actions help ensure that our oil moves to markets that give us the highest oil price possible. I'd next like to focus on the Anadarko Basin, where we dominate several very successful liquids-rich plays, including well-discussed and prolific Granite Wash plays. For this call, though, I'd like to highlight 3 plays that we previously have not highlighted in detail for competitive reasons: the Miss Lime play in Northern Oklahoma and Southern Kansas; and the Cleveland and Tonkawa plays in Western Oklahoma. In the Miss Lime on Slide 20, our total net production averaged over 10,500 BOE per day in the fourth quarter. That's up 31% compared to last quarter and up 141% compared to the period last year. Our current net production is 11,300 BOE per day. Our production mix in the play is approximately 40% crude oil, 15% NGLs and 45% natural gas. The plays on the Chesapeake is one that Chesapeake discovered with the industry's first horizontal well drilled here in 2007 and today is dominated by Chesapeake and our friends at SandRidge. We continue to drill prolific wells across the wide area in Alfalfa and Woods Counties in Oklahoma. We're currently operating 22 rigs in the play and will maintain that level through 2012. To date, we participate in 33 wells that have tested peak oil rates of 500 barrels of oil or more. We previously announced here our intention to bring in a JV partner in the play and hope to have some -- a successful transaction to share with you later this summer. Next, I'd like to cover the Cleveland and Tonkawa plays on Slide 21, where we also have a dominant acreage position. Our total net production from these 2 plays averaged nearly 18,000 barrels of oil per day in the 2011 fourth quarter. That's up 20% compared to the last quarter and up nearly 125% compared to this period last year. Our production mix in this play is 50% crude, 15% NGLs and 35% natural gas. To date, we have participated in 70 wells that tested with peak oil rates of 500 barrels of oil or more. And we are currently operating 20 rigs between the 2 plays and expect to maintain that level through 2012. Next is the Permian Basin on Slide 22, which we recently disclosed we are considering a joint venture or an outright sale. Most recognize that Permian is the most prolific basin in the U.S. and it garners significant incremental capital from the industry at current oil strip prices. Our 1.5 million net acre Permian acreage position is focused on key development plays: the Avalon, Bone Spring, Wolfcamp and Wolfberry. Fourth quarter net production was approximately 33,000 barrels of oil equivalent per day. That's an increase of 23% compared to fourth quarter of last year. And in 2011, we tested 21 wells with an average peak rate of over 1,000 barrels of oil per day. We look forward to sharing more information with prospective partners and/or buyers in our upcoming data approval [ph] process. And finally, I'm pleased to highlight our latest large-scale discovery, the Utica Shale that's on Slide 23. This is where we recently welcomed Total to the wet gas window in the play as our JV partner, as a follow-on transaction to our mutually successful partnership in the Barnett Shale. We are continuing to delineate efforts in the play with 6 rigs running in the wet gas window and one each in the oil and dry gas windows. We will -- plan on ramping up to 20 Utica rigs here by year-end 2012. To date, we've drilled 42 wells in the play, with 7 of those on production and 35 waiting on completion or pipeline connection. Two recent completions included our Burgett and Shaw wells in the Utica, which produced at peak 24-hour rates on average of 700 barrels and 3 million per day. We are already starting to see drilling efficiencies in this play and have our recent best well drilled spud to rig release is only 16 days, and that's compared to 2x or 3x of that for our earlier wells. Through our midstream efforts, we've installed 200 miles of pipeline -- will install 200 miles of pipeline in 2012 and our local field office presence continues to grow. All the major oilfield service providers are establishing a footprint locally as a result of our activity, and this is driving significant boost through Eastern Ohio. Moving onto Slide 24. We are operating 161 rigs and have accomplished approximately 90% of our planned transition to liquids-rich plays. We do expect our operated rig count will stay relatively level for the year at an average of approximately 161 rigs for the year. This is including 33 rigs in the Eagle Ford Shale; 22 in the Miss Lime play; 20 in the Cleveland and Tonkawa plays; 14 in the Utica Shale play; 13 in the Granite Wash plays; and 10 in the Permian Basin. During the remainder of the first quarter and into the second quarter, we will continue to see a drop in natural gas rigs until we get down to 12 rigs in the northeast portion of the Marcellus and down to 6 rigs in the Haynesville. We are already at our stated goal of 6 rigs in the Barnett. We expect to spend $7 billion to $7.5 billion on proved and unproved drilling and completion activities in 2012, approximately 85% of which will be directed towards our liquids-rich plays. Finally, I would like to conclude by highlighting 2 important achievements that demonstrate the company's commitment to best practices in the environmental, health and safety areas, it's on Slide 25. I'm pleased to report that 2011 was Chesapeake's safest year ever in conducting its operations. Our 2011 total recordable incident rate was an impressive 0.53. While our company has continued to grow, our OSHA reportable incidents continued to decrease. Since implementing the SAFE program in 2010, which stands for Stay Accident Free Everyday, COI has improved our safety performance by 34% while increasing employee count. In 2011, we set a new record by working over 1.5 million employee hours without a recordable injury. This is a very important accomplishment, and we are very committed to making 2012 also the safest year in the history of the company. We also make environmental stewardship a priority. And in early 2011, Chesapeake furthered its commitment to progressive operational, environmental and safety standards by formally adopting a set of operational principles for the company's employees, contractors, suppliers and vendors to guide its oil and gas exploration and production operations throughout the country. These guiding principles represent our commitment to our surface owners, mineral owners, local citizens, shareholders, government officials and regulators and all stakeholders to make progress in improving our operational performance by working in an environmentally respectful way. In addition, during 2011, Chesapeake joined a nationwide public registry, fracfocus.org, that discloses the additives in the company's hydraulic fracturing operations. We currently have more than 1,300 wells posted on fracfocus.org, accounting for more than 11% of all the wells posted to date, more than any other operator. In summary, Chesapeake has an outstanding year of operation in 2011, and we look forward to providing further strong growth, particularly in our liquids-rich plays as the year progresses. I would now like to turn the call back to the operator and open the call up for questions. Operator?

[Operator Instructions] And we'll go first to Doug Leggate at Bank of America Merrill Lynch. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: I'm going to try a couple, if I may. On the production outlook, you've kind of caveated in your commentary that the guidance excludes the potential of several deals over the course of this year. My question is really about the longer-term, the target to get to 250,000 barrels a day of liquids. Assuming that you do execute some of the transactions you're talking about, particularly the potential exit to the Permian, how would you see that longer-term trajectory in terms of liquids targets move around? Is it material or will it essentially remain unchanged? Aubrey K. McClendon: Remain unchanged, Doug. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: So can you give us some idea as to what the headroom is? Aubrey K. McClendon: Well, it's enough to handle a full divestiture of the Permian, if that's your question. It's about 5% of our current production, so we have -- continue to have a lot of headroom. You can frankly see it in our curtailments, where we've lowered our guidance. For 2013, I think it was about 50 Bcf on a midpoint perspective, and yet we're modeling a curtailment of about 130 Bcf. So if we weren't curtailing gas, we would actually be taking our gas production up for the year. So I think there's plenty of headroom, and we've modeled that we can still get to our 250,000 barrel number by just reallocating capital away from the Permian to other plays. We have -- actually the benefit of our business strategy is that we have leading positions not just in 1 or 2 plays but in 11, and we can spend additional money in the Anadarko Basin or the Eagle Ford or in the Utica Shale. Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division: Got it. My second one, and I'll leave after the second one really is on the CapEx program and, I guess, the disposal indications that you provided. Specifically on the oilfield services line item, it looks like the CapEx there compared to your previous guidance has moved up a bit. I'm not sure if there's something else in there beyond midstream and oilfield services. But if you could maybe give us some color on that. And at the same time, the $2 billion disposals you're talking about in the midstream, I know there's a lot of moving parts in there. But Nick has previously given some color as to how you guys see the value of those assets. I wondered if you could give us a quick recap on what's making up that $2 billion and what's some of the menu items are there that you might look at. And I'll leave it at that. Domenic J. Dell’Osso: Sure, Doug. This is Nick. We are not really changing our midstream and services CapEx by any material amount. There is a little bit of additional midstream CapEx. You saw yesterday that we had an announcement with a company called Gavilon to jointly develop a pipeline. And there's 2 or 3 other pipelines like that where we have equity options, and together, they amounted to maybe a 10% increase in midstream CapEx. But that's a rough number, and we have -- those are options we have to determine exactly what we're going to do. So we've given ourselves in our guidance here some room to participate in some of those projects, which we think will be highly accretive. Ultimately, though, what we do have there is midstream CapEx, services CapEx. And then we haven't previously given specific guidance on other CapEx, and so that's an additional element here. And other would include seismic. It would include corporate capital expenditures for things like software and other things that get capitalized in our budget. What we really tried to do this time was give a complete picture of our ins and outs, and so we want that in there. We are quite purposefully not giving very detailed, specific guidance on both midstream and services this time. You'll remember that, yes, you've asked in your question here about what are the items that we think will deliver the monetizations. One of those items, we believe, will be an IPO of our services business. And so we need to start being pretty careful about the guidance we provide outside of an SEC process and they'll plan to do that. So it will be that. It'll be midstream dropdowns, and then we said that we would like to see something happen. In fact, that may also have -- has one on file [ph], so there's not a lot we can say about that either.

We'll go next to David Heikkinen at Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just kind of thinking about you gave guidance for Chesapeake Oilfield Services in your projections and then Chesapeake Midstream Development. I know you're talking about doing an oilfield services IPO. Kind of thinking about the margins, though, of revenue versus operating expenses, they look a little low but then they expand. Can you walk through what your assumptions are that go into -- versus that sort of guidance? Domenic J. Dell’Osso: Sure. We, at the moment, are just entering the pressure pumping business. We frac-ed our first well in the fourth quarter. We now have 2 spreads running, terrific success early in the life of Performance Technologies, LLC, our frac-ing company and look forward to continuing to grow that business. That is, of course, a high-margin business relative to the overall base that we have there, which is dominated by our contract drilling business. And so we do expect the margins to improve as a result of the rollout of PTL. You probably will notice that the fourth quarter margins on a summary basis show a little bit less profit from COS. One thing that did occur there is we did have some additional roll-off of contracts that we're operating previous to our Bronco acquisition for third parties. And so as those rigs go to work for Chesapeake wells, we obviously have to eliminate a bit of that profit, whereas in the third quarter, that was pure profit to Chesapeake working for a third party. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And then thinking about if you -- as you talk about that IPO selling roughly 20% of the business is a target, is that a reasonable assumption? Domenic J. Dell’Osso: That's a reasonable assumption, David. We're way early to give you any firm guidance on that. But that's as reasonable assumption for now as anything. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And if you sold more than 20%, does that have any tax implications? Or would that change how you'd have to report capital expenditures or anything along those lines? Domenic J. Dell’Osso: Those are all the things that we're looking into. And we don't have a structure finalized yet that we'll pursue. So I'd like to just pass on that. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. Now shifting kind of to the operating side. One of the thoughts and questions around your Permian assets and, Steve, you talked a little bit about the wells, 21 wells, in 2011. Can you give us a breakdown of what zones -- just a split of what those wells were to get an idea of how many acres you have in each play and kind of where you've actually had well results? Steven C. Dixon: This is Steve again. I mean, it's predominantly in the Avalon and Bone Spring in the Delaware Basin. We do have 3 rigs running in the Midland Basin and Wolfberry play. But it's predominantly those big wells that are all in the Bone Spring and Avalon. Aubrey K. McClendon: David, this give us an opportunity to say one thing. We did see in some analytical work over the last day that there is a view that we went out and acquired 800,000 acres in the fourth quarter in the Permian. That's not correct. What people, I think, are referring to is, Jeff, it would have been on our third quarter report, where we showed how many acres and announced 1.5 million, and the reason is because you had 600,000 acres in the other category. Jeffrey L. Mobley: Yes, correct. In the third quarter drilling inventory, we had listed a portion of our Permian Basin acreage in the unconventional liquids-rich plays. As I recall, that was 820,000 or 830,000 acres. Also there was approximately 650,000 net acres in the bottom category that's grouped of our other conventional and unconventional plays. So we had 1.5 million net acres in the Permian at the third quarter. We have the same amount of acreage to date. And also for a point of reference, I'll also guide you to our disclosures in our annual report last year, where we had reported 1.2 million net acres in the Permian. So no big acreage spend and some others have kind of missed that point.

We'll move next to Dave Kistler at Simmons & Company. David W. Kistler - Simmons & Company International, Research Division: Real quickly, taking the rig count down to 12 in the Marcellus, 6 in the Haynesville, 6 in the Barnett, obviously could certainly redirect that capital towards other liquids-rich assets. What's the incentive for keeping those rigs running there at all? Does that have to do with pipeline obligations? If you could just walk me through that, I'd appreciate it. Aubrey K. McClendon: So it's primarily a combination of things, Dave. There is still some acreage lockdown that needs to occur in all those plays that will tend to peel off or become less of an item for the Haynesville as we go through the year. In the Barnett, we have permits that may be kind of "use it or lose it" type of permits. And so for the initial well on a pad, we want to get a well into production and then we can hold off on the incremental drilling after that. There are some FTE, some transport issues in some of the plays, but we're willing to try and take some of that and also going to try and renegotiate and kind of reshape some of our firm transports as well. So I've heard some companies say because of firm transport, they'll discontinue to drill gas wells and lose money. And our view is we should be able to take a little more commercial approach to that. So I'd just say it's a combination of things that put us in a position where we can go to these levels on an absolute well basis, and then we'll take a look at it from here. These levels of drilling do provide or cause a decline in our production in the Barnett, a decline in our production in the Haynesville. So we think that's certainly a good thing for the marketplace and we look forward to that playing out to the marketplace in 2012 and beyond. David W. Kistler - Simmons & Company International, Research Division: Great. And then looking at kind of your '13 guidance and comparing it to your '12 guidance, dry gas production is getting about $900 million of CapEx in '12. Then in '13, you didn't adjust that production guidance down from what you gave us at 3Q. Is there going to be an uptick in CapEx to dry gas production at this point? Or is that the anticipated plan? Aubrey K. McClendon: David, I just don't think we know enough about what the gas markets is going to look like in 2013, so we kept it to where it is for now. And well -- and also we have a significant curtailment this year as well of 130 Bcf. So I think there's -- if the gas market is attractive enough, there's a likelihood that we could produce more gas in 2013 than what we presently have modeled. David W. Kistler - Simmons & Company International, Research Division: Okay, appreciate that. One last one if I can, looking at your commentary around the financial transaction for Ellis and Roger Mills Counties in Oklahoma, Cleveland, Tonkawa, I'm guessing kind of same sort of structure to what you've previously done in the Utica. If we think about that as sort of 7% financing before an overriding royalty interest, how do I compare that to then debt financing you just did at 7%? Realizing you want to hit investment-grade rating, that 7% seems attractive versus giving up an overriding royalty interest and a 7% distribution to the financial partner. Domenic J. Dell’Osso: Sure, Dave. I'll take that. We really view that transaction as an alternative to a strategic JV. Strategic JVs in this part of the world are complicated for us because of the overlapping geologic plays that exist and so we can take a specific zone and do this financial transaction. The relative cost of capital to a strategic JV is vastly different here, given the structure. The overall return on this one will be less than the Utica just because this one includes the current production and reserves and is a more well-defined play. But you're right, it will be a similarly structured investment.

We'll go next to Jeff Robertson at Barclays Capital. Jeffrey W. Robertson - Barclays Capital, Research Division: Aubrey or Steve, in the Utica, you all talked about having one well active in the oil part of the play. Can you talk about your plans for the oil part and whether that's included in the Total joint venture that you all announced back at the end -- in December? Aubrey K. McClendon: Yes, sure, Jeff. First of all, it wasn't one well, it's one rig running in the oil window and then one in the dry gas window. So think about, if you would, the Utica having 3 phases, just like the Eagle Ford, except rather than the south to north on gas to oil in the Eagle Ford, in the Utica, we go east to west, so gas on the east side and wet gas in the middle, and then oil on the west side. The deal we did with Total is simply right in the middle, it's the wet gas window, and we purposely kept our dry gas assets back for a better day. And then on the oil side, we just simply haven't drilled enough wells to be able to establish just what our EURs are going to be there. So there's a lot of interest in that joint venture with us on the oil side, and interestingly enough, a fair amount on the gas side as well as there are a number of companies that are signed up to export gas from the U.S. or planning to export gas from the U.S. want to back that up with some physical assets. And the Utica would be a great place for them to go. So we have about 400,000 acres in the dry gas window, and I think about 400,000 in the oil window as well. So we're going to continue to develop both of those sides of the play, but the primary amount of our drilling will be in the wet gas window. Jeffrey W. Robertson - Barclays Capital, Research Division: Aubrey, will you run -- will you all have more than one rig out there over the course of this year in your oil part of the play trying to test that? Aubrey K. McClendon: Yes, probably go up to maybe 2. And I think, Steve, we exit 2012 with how many rigs in the... Steven C. Dixon: 20 rigs. 20, we're at 9 today, is that right? Aubrey K. McClendon: Yes, so it's going to be kind of proportional, I would say, Jeff, as we more or less double our wet rig count, we'll do the same on our dry and oil. Jeffrey W. Robertson - Barclays Capital, Research Division: Okay. And then moving over to the Rockies. Can you all just provide an update on where you stand in Niobrara and what your plans are for that for 2012? Aubrey K. McClendon: Yes, I'll let Steve provide a little more detail. I mean, on the DJ Basin, like with other companies, our results have been spotty. And today, I don't think we're drilling anything in the DJ Basin in the Niobrara. On the other hand, our Powder River Basin play is working quite well. And Steve may want to highlight a couple of some wells there or highlight what our activity levels are going to be there. Steven C. Dixon: Yes. We're just going to get ramped up to last year. we're up to 8 rigs in the Powder River now, wanting to grow that to maybe 15 by the end of the year. And, again, we're seeing 500 barrel a day IPs there. So we have some delineation to do. But as we bring in extra rigs, we can start focusing part of those in sweet spot also. So we're looking forward to Powder River and the Niobrara. Aubrey K. McClendon: I might also mention that it's in both of those areas, it's not just the Niobrara. We're investigating lots of different other formations as other operators are as well. So I think for the DJ, I wouldn't say all is lost as you're outside of Greater Wattenberg, but there's going to be some other ideas. But we have certainly shifted our focus on the Niobrara play to the Powder River Basin. Jeffrey W. Robertson - Barclays Capital, Research Division: Last question, Aubrey. Can you comment if you contemplate exiting a complete exit of the Permian, can you compare the results that you all -- the returns that you all anticipate on the different plays in the Permian to what you'll be keeping in the Eagle Ford and the Utica and the Mid-Continent liquids plays? Aubrey K. McClendon: Sure. I mean, I think the returns from our projects in the Permian are first-rate. And I think that's why you see so much industry interest in the Permian, and frankly, why you see so much investor interest. I think if our -- just looking at the valuation of some companies that are pure Permian Basin players, we're tempted to spin out our Permian asset and just make it a separate company. But at the end of the day, it's probably best for our overall goals this year to work the JV approach and also to also work the 100% approach as well. So Bone Spring, Wolfcamp, Avalon, these are all plays that everybody wants to be in. And I don't need repeat the rate of returns that everybody is talking about getting there. But they're very strong, and our situation is just a real simple one. We're making the transition from strictly gas to oil, and along the way, we need to sell some of the assets that we developed. And this is an asset that we think that will attract a great deal of industry interest. And also from our perspective, it only being 5% of our production, it was never going to be a play like the Eagle Ford, where right now we're spending 25% of our CapEx on it. Likewise, a play like the Utica could ramp up over time to be a very significant player. We're spending about 25% of our CapEx in the Anadarko Basin. We just didn't see the Permian ever getting to a point where it could be as important to us as some of these other assets. So that's why we are considering the various asset monetization proposals that we've talked about.

We'll go next to Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs Group Inc., Research Division: Appreciate the additional operational disclosure by play on the call, and wanted to follow up a bit for some more color on the 2 Utica wells that you referenced. Specifically, if the wells from a lateral length perspective are analogous to the 2 Carroll County wells you disclosed in mid-September, how much of the liquids are oil condensate versus NGLs? And then with the drilling efficiencies that you're seeing, what your drilling and completion costs are in the play? Steven C. Dixon: I don't have the lateral lengths with me, Brian, but they should be average. I don't think they were any longer. And those are preprocessed that was condensate production on those wells, averaging over 700 Bs. Capital costs are -- still a lot of science going on, a lot of pilot holes, still learning a lot. So as you can see from 45 days and some 16 days, there's a variety of cost also. Aubrey K. McClendon: But it's 18 to 20 days, we should be able to get costs down to what... Steven C. Dixon: We can get it down below $6 million. Aubrey K. McClendon: Brian, that's what I kind of about on our long-term plan is a $5.5 million to $6 million CapEx plan for, let's call it, a 5,000 foot lateral or so. Brian Singer - Goldman Sachs Group Inc., Research Division: That's helpful. And so from the wells that you've drilled and completed and brought on now, what percentage of your wet gas acreage would you say you feel like you've derisked? I mean, there's been a lot of focus on -- it seems like a lot of focus on Carroll County. Or do you feel like you've derisked a much wider chunk of that acreage at the moment? Aubrey K. McClendon: Well, I think we feel like we've derisked 100% of our wet gas acreage, given not only just our results to date but also just our petrophysical work to date. And remember, this is a formation that's been penetrated hundreds of times, as companies have drilled to deeper objectives like CNOOC [ph]. So we're 100% confident on the wet gas, 100% confident on the dry gas. It's the oil that we still haven't yet fully proved up how much of that is going into be prospective. There's a lot of other operators that are going to be throwing results out into the marketplace in the next -- well, throughout 2012. The difference is, I think, most people will look at this play see where our acreage is concentrated and think that we've got really the heart of the core pretty much locked up. And so we're very excited that we're likely to be able to deliver the best results. But my hope is that other operators who are around the fringes will also have success as well and that can only benefit us at the end of the day. Brian Singer - Goldman Sachs Group Inc., Research Division: That's helpful. And then lastly, you highlighted a decent backlog in the Eagle Ford Shale and then it led to a lesser degree in the Utica. Can you just talk to how and when would you expect that to change in 2012? Is it just bringing on the additional frac crews in the Eagle Ford or the midstream bottlenecks that you anticipate easing or not easing as well? Steven C. Dixon: Brian, this is Steve. It's really both. It's ramping up our ability through the services to complete wells faster and more efficiently, but also is the midstream and we've got a lot of activity going on there now. And our ability to transport oil is increasing significantly just in the last few months and in the coming months. Brian Singer - Goldman Sachs Group Inc., Research Division: So you do expect the 200 well backlog in the Eagle Ford to be entirely used or 50% used by the end of the year? Or does the ramp offset the -- there's an offset by the ramp-up in activity? Steven C. Dixon: No, we expect to get work off this year. That's why we're going from 7 frac crews to 13.

We'll go next to Neal Dingmann of SunTrust. Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division: Just one clarification, Aubrey. Did you say -- when you just talked about just briefly now on the Utica cost, could you comment again what, on that liquid window, what the costs are running now for you or Steve? And then kind of well design, what's your -- kind of on laterals, if you could comment there. Aubrey K. McClendon: What I said before, a 5,000-foot lateral, we're driving towards $5.5 million to $6 million well. And of course, to get there, we need to be doing enough science to it, and that's been really what we're moving into as the science part is over now to go knock it out. And Steve mentioned we've already got a 16-day well. And I think some of our first wells are 40 to 45 days. So it's really at pretty attractive depths. TVD, Steve, here is 6,000 to 7,000 feet. So we're nearly as deep as a number of the unconventional plays. So we've said from the beginning we love this play, and we're very excited about what we've seen to date. The dry gas is going to work when gas prices get a little better. And then on the oil side, we hope to have some breakthroughs this year as well and hope others in the industry do also. Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division: Okay. And then just one follow-up, Aubrey or Steven. In the Eagle Ford area, are you mostly doing now pad drilling there? And then the second part of that, do you believe -- have you looked and do you believe there could be other prospective liquids zones in parts of that play, in addition to the Eagle Ford? Steven C. Dixon: On the pad -- this is Steve. On the pad drilling, we've only been able to dedicate just a few of our rigs to pad drilling, most of them are still out holding new leasehold. And we have not come across another liquids play yet. There is certainly a dry gas play in the Pearsall, but we're not looking for dry gas right now.

And next, we'll move to Marshall Carver of Capital One Southcoast. Marshall H. Carver - Capital One Southcoast, Inc., Research Division: On the third quarter call, you all had 1.4 million net acres in the Mississippian plays. I think I had 1.1 million in the original play and then 300,000 net acres in the extension. Then in last week's release, you're talking about 1.8 million net acres in the Mississippi Lime plays. Where would you classify those 1.8 million acres? And where did the extra 400,000 acres go? Aubrey K. McClendon: We're only buying in the core right now, so it depends -- other companies may have a different definition of the core and have a different definition of the extension. But we're trying to focus our leasehold buying in areas where we're pretty comfortable with what the outcome is going to be. Marshall H. Carver - Capital One Southcoast, Inc., Research Division: So you were very active in the Mississippian acreage part over the last 3 months. Aubrey K. McClendon: Yes, although starting to slow down as things get blocked up. But yes, it's one of our remaining plays where there's still some acreage to be picked up. And given the level of interest that we see in our Mississippi Lime joint venture, there's a lot of value to be captured for our shareholders by making sure we square up our positions before we enter into a JV. Marshall H. Carver - Capital One Southcoast, Inc., Research Division: Okay, that's helpful. And one more question. On the long-term liquids growth target to the 250,000-plus barrels a day in 2015, how should we think about that in terms of crude production or condensate versus NGLs? Do you have any color on that front? Aubrey K. McClendon: Yes, I think we've modeled it about the same way that our production is today. Steve, do you have that? Or Nick, do you have the split? Domenic J. Dell’Osso: I think the split is about 35% to 40% NGLs, and the balance being crude and condensate. Aubrey K. McClendon: So yes, just to call it, mid-60s, maybe 2/3 oil, and the rest is in NGLs. And that's where it is today and where we expect it to remain.

We'll go next to Biju Perincheril with Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: A couple of questions. On the gas production side, Aubrey, in 2012 numbers, I think, you're only looking at about a 5% drop versus the previous guidance. And I would have expected something more, given the curtailments. So the question is, what is embedded into that guidance as far as when you think those production will be back on? Aubrey K. McClendon: Yes, really, the answer is simply that had we not curtailed production, we would've well exceeded our production forecast for 2012 and would've had to take it up. So I think I've mentioned this in an earlier question, which is, we went down from 1,020 to 970 Bcf, and then are also curtailing, though, 130 Bcf, or we're at least planning on it. But we don't know how the year will play out. So obviously, we would've had to increase our guidance for 2012 for gas production had we not chosen to curtail as much as we're now curtailing. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Got it. But you're not assuming that production stays soft for the rest of the year, though. Is that -- is that a fair assumption? Aubrey K. McClendon: I think we have it internally modeled to be off through October. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. And then on '13, and I think you mentioned earlier that you're just waiting to see how the markets shape up before you give more specific guidance or updated the 2013 guidance. But given the reduction in activity to date, do you need to increase from current levels to hit the guidance that you have provided now for gas? Aubrey K. McClendon: I'm sorry, to do what levels? I missed the word, I'm sorry. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: To meet the guidance that you provided now for 2013, do we need to see an increase in gas activities? Aubrey K. McClendon: No, I mean, we're low on gas right now. So I wouldn't -- on your list of concerns about our ability to meet 2013 gas guidance, I think I'd mark that one off. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. So with the activities there, you are still looking at an increase? Even with the reduced activities, you're still looking at a slight increase in 2013? Aubrey K. McClendon: Yes, we are. And again, without knowledge of the gas market. But we've got -- if you were to do this -- if you look at our midpoint of the range this year at 970 Bcf and add 130 Bcf, that means our true capacity this year was 1,100 Bcf or 1.1 Tcf. And so we're modeling next year 1,050 Bcf. So we were modeling at a 4% decline 2013 from full capacity in 2012. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: But I mean, that's pretty remarkable, given the kind of drop in activities that you're talking to still get that uptick. Is that because of activities that are in more liquids-rich and the associated gas production? Or is just the areas -- the shale plays are that much more prolific than you've been thinking? Aubrey K. McClendon: Well, I appreciate you recognizing that performance is remarkable, it is. And that's what's driven gas production levels in the U.S. to where they are, we're responsible for 30% of it. So we feel also somewhat responsible for trying to contain ourselves a little bit. I think when you just boil it down, it's just the sheer productivity on a per well basis. So the play cycle times are down, recoveries on a per well basis are up. Associated gas helps a little bit, but it's not nearly the factor that I've read a lot of people -- and what I see a lot of analysts do is just model an associated wedge for the industry and just put it on top of flat shale production. We think that the declines from the Barnett and the Haynesville will offset the -- any gains from the Marcellus, and then we think the rest of the system they then decline. So when you take us out of the system as being a contributor to growth, it's pretty hard for the rest of the system to grow. And we'll wait for demand to catch up. We absolutely believe that will be the case, and we see evidence of it every day from -- if you burn diesel in the U.S. today, you are absolutely focused on trying to burn natural gas instead and can read more evidence of that every week in terms of what companies are doing to embrace it. So we're well on our way to the demand revolution in natural gas that will solve the overhang that we are experiencing today.

We'll take our next question from Bob Brackett at Bernstein. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Could you give us an update on the Williston Basin? You've deemphasized it a bit. Are you doing more science there? Are you more positive, more negative? Aubrey K. McClendon: Bob, yes, we drilled a couple of wells up there and not crazy about what we found to date, so kind of recalibrating there. We have just under 0.5 million acres kind of south of Dickinson and really to the Three Forks idea for us. And I suspect the western part of our acreage, which is kind of abuts where Whiting is operating, will probably work out fine. We drilled our initial wells more towards the south than the east. So disappointed to date in what we've seen in the Bakken, but have a huge acreage position there. We didn't spend a whole lot of money on it, so not too worried about that. And really, just moving our rigs over to the western side of the play and kind of cozy up a little bit more to what Whiting is doing there. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Okay. As a follow, on those 1,250 non-op wells from 2011, can you talk about where those are in the mix of horizontal-vertical, oil-gas and what the call-in capital of that non-op program might be? Aubrey K. McClendon: Yes, we can answer that. They're probably -- I mean, virtually all horizontal. There's hardly anybody we do business with is drilling vertical wells. Steve, in our overall budget, are we 20% non-op? What's our... Steven C. Dixon: It's up 15%. Aubrey K. McClendon: So we're about 15% non-op, Bob. Steven C. Dixon: And of course, Bob, that is included in our CapEx guidance. Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division: Sure, sure, sure. And where are those? Those mostly Mid-Continent? Steven C. Dixon: Yes, Western Oklahoma. Aubrey K. McClendon: Scattered, a lot in Marcellus. We have non-op positions there. Not so much in places like the Eagle Ford or the Utica, where we are the operator. But I'd say Permian, Mid-Continent and Marcellus are the main areas where we have the non-op interest.

And we'll go next to Joseph Allman at JPMorgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Aubrey, in terms of leasehold acquisitions. So I know you're budgeting to spend $1.4 billion net. Given that you're ramping up in the Mississippian, how much have you spent so far gross if you can give us that number? And when you say $1.4 billion net, is that net of just the existing JVs? Or are you factoring in future JVs as well? Aubrey K. McClendon: Yes, good question, Joe. The net is from reimbursement from existing partners. So initial first-time down payments on leasehold are not included in that. So it's really not a gross number, it's just like there's no such thing as gross CapEx. You go drill a well and your partners reimburse you for their share of the CapEx cost and you report your net CapEx, and that's what we do on undeveloped leasehold. We do have partners who have obligations to buy leases alongside us. So $1.4 billion is what we spend and that does include some partner reimbursement, but does not include expected payments from first-time JVs or from just leasehold we will sell just in the ordinary course that may be superfluous to our core operations. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. So just to clarify. So you're going to spend $1.4 billion net on leasehold this year, that's your target. Now you've spent money late last year and early this year ramping up the Mississippian. So you don't have a Mississippian JV yet. So that $1.4 billion, that includes what you've spent so far in the Mississippian. But does it also make an estimate of not necessarily the upfront payment, but the reimbursements you get for the future Mississippian JV? Aubrey K. McClendon: Okay. Let me try and clarify a couple of things. First of all, you commented that the $1.4 billion includes all we've spent to date on the Mississippian. No, it's our expected expenditure this year, of which some of it will be the Mississippian. And in that, we do anticipate that there will be, later in the year, some partner pickup of some of our leasehold. But it is not net of the initial down payment that a partner makes when they come into the Mississippian. So the primary driver of the $1.4 billion this year, I think, we've budgeted to spend more in the Utica than anywhere else. And then after that, it kind of falls down pretty rapidly into a wide variety of plays, where we continue to kind of square up positions. So that's -- I hope that makes sense to you. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Yes, it doesn't necessarily fill in the details, but -- so will the leasehold spending be concentrated in the first quarter versus the balance of the year? Aubrey K. McClendon: No, I don't know it's going to be concentrated. It's going to be more front end-loaded because again, we project that we're spending less money in the third and fourth quarters in the Utica than we are in the first and second quarter. And the first quarter always has some spillover from the fourth quarter of the preceding year. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay, okay. I think I understand. And then -- so a different topic. So in terms of working capital, one thing we noticed is that in the fourth quarter 2011, the change in working capital saw a big increase and it was bigger than we saw in prior quarters for a while. And we just want to get behind the numbers. I know we spoke to guys last night, and I know part of it is just prepays from partners. So could you guys actually explain that? And also, in terms of accounts payable, are you managing your accounts payable any differently than you had been? Domenic J. Dell’Osso: No, Joe, this is Nick. There's a lot of activity that occurred in the fourth quarter that resulted in higher total current liabilities. No difference of how we manage our AP. We do have partner prepays that resulted in higher accrued liabilities.The way that works is when we have significant partner relationships like we do in our JVs, we have the ability to prepay or to prebill them for CapEx. And when they pay that to us, it becomes an accrued liability until such time as we form the activity, and then that is reclassed into the full cost pool as an assets. So there's no change into how we're doing things. I do think that as we spend less on leasehold this year than we did on a run rate in the fourth quarter and for the year, you can see that number come down a little bit this year. Certainly, we will be growing our rig count not at all, in fact, for the first quarter, it will be dipped a little bit. So our activity levels in general will come down a little bit in the first quarter, and so we'll see where it all shakes out. There's always a lot of timing differences in that number. For example, we had some proven interest expense that just based on the timing of when 9/30 hits versus 12/31 hits, was a bigger number in the 12/31 balance. So there's always some [indiscernible]. Aubrey K. McClendon: Okay, anything else? Joe, given the time, I'm going to let you call Jeff back on that and let everybody else get back to their business. Thanks for your questions today and appreciate everybody else's participation. If you have follow-up questions, please direct them to Jeff or to John. And we'll talk to you guys down the road. Thank you much.

And that does conclude today's conference. Again, thank you for your participation.