Overview
The following table sets forth certain information regarding the production
volumes, natural gas, oil and NGL sales, average sales prices received, other
operating income and expenses for the three and nine months ended September 30,
2012 (the "Current Quarter" and the "Current Period", respectively) and the
three and nine months ended September 30, 2011 (the "Prior Quarter" and the
"Prior Period", respectively):
                                              Three Months Ended            Nine Months Ended
                                                 September 30,                September 30,
                                              2012           2011           2012          2011
Net Production:
Natural gas (bcf)                              302.3          254.2          848.6         731.9
Oil (mmbbl)                                      9.0            4.6           22.3          11.7
NGL (mmbbl)                                      4.1            4.1           13.0          10.2
Natural gas equivalent (bcfe)(a)               381.1          306.2        1,060.5         863.3
Natural Gas, Oil and NGL Sales ($ in
millions):
Natural gas sales                         $      543      $     861     $    1,359     $   2,412
Natural gas derivatives - realized gains
(losses)                                          52            364            391         1,322
Natural gas derivatives - unrealized
gains (losses)                                   (90 )          (28 )         (401 )        (693 )
Total natural gas sales                          505          1,197          1,349         3,041
Oil sales                                        792            386          2,038         1,048
Oil derivatives - realized gains (losses)         25             (8 )            6           (51 )
Oil derivatives - unrealized gains
(losses)                                         (14 )          645            803           247
Total oil sales                                  803          1,023          2,847         1,244
NGL sales                                        129            180            401           432
NGL derivatives - realized gains (losses)          -            (12 )           (9 )         (31 )
NGL derivatives - unrealized gains
(losses)                                           -             14             34             2
Total NGL sales                                  129            182            426           403
Total natural gas, oil and NGL sales      $    1,437      $   2,402     $    4,622     $   4,688
Average Sales Price (excluding gains
(losses) on derivatives):
Natural gas ($ per mcf)                   $     1.80      $    3.39     $     1.60     $    3.30
Oil ($ per bbl)                           $    88.07      $   84.18     $    91.31     $   89.78
NGL ($ per bbl)                           $    31.22      $   44.04     $    30.86     $   42.17
Natural gas equivalent ($ per mcfe)       $     3.84      $    4.66     $     3.58     $    4.51
Average Sales Price (excluding unrealized
gains (losses) on derivatives):
Natural gas ($ per mcf)                   $     1.97      $    4.82     $     2.06     $    5.10
Oil ($ per bbl)                           $    90.79      $   82.47     $    91.55     $   85.45
NGL ($ per bbl)                           $    31.22      $   41.16     $    30.17     $   39.10
Natural gas equivalent ($ per mcfe)       $     4.04      $    5.78     $     3.95     $    5.94
Other Operating Income(b) ($ in
millions):
Marketing, gathering and compression net
margin                                    $       42      $      30     $       79     $     100
Oilfield services net margin              $       36      $      35     $      125     $      89
Other Operating Income(b) ($ per mcfe):
Marketing, gathering and compression net
margin                                    $     0.11      $    0.10     $     0.07     $    0.12
Oilfield services net margin              $     0.09      $    0.11     $     0.12     $    0.10

                                               Three Months Ended              Nine Months Ended
                                                  September 30,                  September 30,
                                              2012             2011           2012            2011
Expenses ($ per mcfe):
Natural gas, oil and NGL production       $     0.84       $     0.92     $     0.95       $    0.91
Production taxes                          $     0.14       $     0.16     $     0.13       $    0.16
General and administrative expenses       $     0.39       $     0.49     $     0.41       $    0.47
Natural gas, oil and NGL depreciation,
depletion and amortization                $     2.00       $     1.38     $     1.75       $    1.33
Depreciation and amortization of other
assets                                    $     0.17       $     0.24     $     0.22       $    0.24
Interest expense(c)                       $     0.10       $     0.01     $     0.06       $    0.03
Interest Expense ($ in millions):
Interest expense                          $       38       $        4     $       67       $      18
Interest rate derivatives - realized
(gains) losses                                     -                -              -               6
Interest rate derivatives - unrealized
(gains) losses                                    (2 )              -             (4 )            13
Total interest expense                    $       36       $        4     $       63       $      37


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(b) Includes revenue and operating costs and excludes depreciation and amortization of other assets.

(c) Includes the effects of realized (gains) losses from interest rate derivatives, but excludes the effects of unrealized (gains) losses and is net of amounts capitalized.

We are the second-largest producer of natural gas, a top 12 producer of oil and NGL (collectively "liquids") and the most active driller of wells in the U.S. We own interests in approximately 46,700 producing natural gas and oil wells that are currently producing approximately 4.0 bcfe per day, net to our interest. The Company has built a large resource base of onshore U.S. natural gas assets in the Haynesville and Bossier Shales in northwestern Louisiana and East Texas; the Marcellus Shale in the northern Appalachian Basin of West Virginia and Pennsylvania; and the Barnett Shale in the Fort Worth Basin of north-central Texas. In addition, we have built leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas; the Utica Shale in Ohio, West Virginia and Pennsylvania; the Granite Wash, Cleveland, Tonkawa and Hogshooter plays in the Anadarko Basin in western Oklahoma and the Texas Panhandle; the Mississippi Lime play on the Anadarko Basin Shelf in northern Oklahoma and southern Kansas; and the Niobrara Shale in the Powder River Basin in Wyoming. We have also vertically integrated many of our operations and own substantial midstream, compression and oilfield services assets.
Proved Reserves. Chesapeake began 2012 with estimated proved reserves of 18.789 tcfe and ended the Current Period with 16.222 tcfe, a decrease of 2.567 tcfe, or 14%. The Current Period's proved reserve movement included 1.060 tcfe of production, 4.474 tcfe of extensions, 4.878 tcfe of downward revisions resulting primarily from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended September 30, 2012, compared to the twelve months ended December 31, 2011, and 596 bcfe of other downward revisions. During the Current Period, we acquired 37 bcfe of estimated proved reserves and divested 544 bcfe of estimated proved reserves.
In the Current Period, we reduced our estimate of proved reserves by 5.474 tcfe primarily due to the impact of lower natural gas prices. Natural gas prices used in estimating proved reserves as of September 30, 2012 decreased by $1.29, or 31%, to $2.83 per mcf from $4.12 per mcf as of December 31, 2011 using the trailing 12-month average prices required by the Securities and Exchange Commission (SEC). The reserve reductions included the loss of significant proved undeveloped reserves, primarily in the Barnett Shale and the Haynesville Shale plays, for which future development is uneconomic at the natural gas prices used in the reserves estimates. As a result of lower estimated reserves, as of September 30, 2012, we were required to impair the carrying value of our natural gas and oil properties and, if the trailing 12-month natural gas, oil and NGL prices are lower in subsequent future periods, we could have additional impairments in the future. An impairment of this type is a non-cash charge that does not impact our liquidity or our ability to comply with financial covenants. Future impairments of the carrying value of our natural gas and oil properties, if any, will be dependent on many factors, including natural gas, oil and NGL prices, production rates, levels

of reserves, the evaluation of costs excluded from amortization, the timing and impact of asset sales, future development costs and service costs. We refer you to the risk factor "Declines in the prices of natural gas and oil could result in a write-down of our asset carrying values" included in Item 1A of our 2011 Form 10-K and the discussion of the full cost method of accounting under Application of Critical Accounting Policies - Natural Gas and Oil Properties in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2011 Form 10-K. In addition, see Natural Gas and Oil Properties in Note 1 of our condensed consolidated financial statements included in Part 1, Item 1 of this report.
Drilling and Completion Expenditures. During the Current Period, we invested $7.360 billion in drilling and completion costs on proved and unproved properties, of which approximately 90% was related to operated wells (using an average of 145 operated rigs) and approximately 10% was related to non-operated wells (using an average of 72 non-operated rigs).
Production. Our Current Quarter production of 381.1 bcfe consisted of 302.3 bcf of natural gas (79% on a natural gas equivalent basis), 9.0 mmbbls of oil (14% on a natural gas equivalent basis) and 4.1 mmbbls of NGL (7% on a natural gas equivalent basis). Daily production for the Current Quarter averaged 4.142 bcfe, an increase of 813 mmcfe, or 24%, over the 3.329 bcfe produced per day in the Prior Quarter.
Our Current Period production of 1,060.5 bcfe consisted of 848.6 bcf of natural gas (80% on a natural gas equivalent basis), 22.3 mmbbls of oil (13% on a natural gas equivalent basis) and 13.0 mmbbls of NGL (7% on a natural gas equivalent basis). Daily production for the Current Period averaged 3.870 bcfe, an increase of 708 mmcfe, or 22%, over the 3.162 bcfe produced per day in the Prior Period.
During the first half of 2012, Chesapeake curtailed approximately 60 bcf of net natural gas production, or an average of approximately 220 mmcf per day of natural gas spread across the Current Period. We undertook these curtailments in response to continued low natural gas prices. The curtailed volumes were located primarily in the Haynesville and Barnett shale plays. We ended our natural gas production curtailment program at the end of the 2012 second quarter. Leasehold and Seismic Inventories. Since 2000, Chesapeake has built a leading position in 10 of what we believe are the top 15 unconventional plays in the U.S. We are currently using 88 operated drilling rigs (net of nine rigs we are operating on behalf of purchasers of our Delaware Basin assets in the Permian Basin) to further develop our leasehold inventory. We are targeting to invest approximately $1.750 billion in undeveloped leasehold expenditures, net of reimbursements from joint venture partners, in 2012, of which approximately 90% will be in liquids-rich plays and all of which will be in plays where the Company is already active. This compares to net undeveloped leasehold expenditures of approximately $3.5 billion and $5.8 billion in 2011 and 2010, respectively.
Emphasis on Increasing Liquids Production. In recognition of the value gap between liquids and natural gas prices, Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise during the past four years to identify, secure and commercialize new unconventional liquids-rich plays. This planned transition will result in a more balanced and, we believe, more profitable portfolio between natural gas and liquids. In the Current Period, our production of liquids averaged approximately 128,900 bbls per day, a 61% increase over the Prior Period average, as a result of the increased development of our unconventional liquids-rich plays. We project that the portion of our operated drilling and completion expenditures allocated to liquids development will reach approximately 85% in 2012, and we expect to increase our liquids production through our drilling activities to an average of approximately 130,000 bbls per day in 2012, 170,000 bbls per day in 2013 and to reach 250,000 bbls per day in 2015.
Sales. Our business strategy is to create value for investors by building, developing and now harvesting what we believe is the largest onshore natural gas and liquids-rich resource base in the U.S. After years of building our resource base, we plan to focus on the 10 plays where we have a #1 or #2 ownership position and to sell assets that are non-core or do not fit our long-term plans. During the Current Period, we completed sales for proceeds of approximately $5.7 billion, have completed sales through November 7, 2012 for $8.4 billion and we have announced our intention to sell natural gas and oil properties, midstream, oilfield services and other assets that will bring expected total proceeds to $17 - $19 billion in 2012 - 2013. Our sales program, together with operating cash flow and borrowings under our corporate revolving bank credit facility, is designed to fully fund the Company's 2012 capital expenditure program and reduce the Company's long-term debt, although we may not reach our previously announced goal of $9.5 billion by year-end 2012 until 2013. In 2013, we expect to continue to sell assets to supplement operating cash flow to fund capital expenditures and maintain long-term debt at no more than $9.5 billion. We refer you to risks associated with our sales plans, as described in Planned Sales below.

Capital Expenditures
In the Current Period, our capital expenditures for exploration, development and acquisition activities, net of drilling and completion carries of $655 million, were $9.550 billion, including $7.360 billion for drilling and completion costs, $1.850 billion for acquisitions of unproved properties (excluding $228 million of reimbursements for unproved leasehold from our joint venture partners) and $340 million for acquisitions of proved properties. We incurred a disproportionately high percentage of our total budgeted 2012 capital expenditures early in the year as the result of several factors which are discussed further below. Our current budget for 2012 includes drilling and completion capital expenditures, net of drilling and completion carries, of $8.750 billion and undeveloped leasehold expenditures of $2.030 billion, excluding reimbursements for unproved leasehold from our joint venture partners. We anticipate receiving approximately $280 million in reimbursements for unproved leasehold from our joint venture partners in 2012.
Drilling and completion costs during the Current Period reflected the impact of our deliberate transition to liquids-focused drilling and reduced natural gas drilling. During the 2012 first quarter, our rig count was as high as 165 rigs as we were quickly ramping up our liquids-focused drilling while, at the same time, we were gradually ramping down drilling of natural gas wells. As of November 1, 2012, our rig count had been reduced to 88 rigs (net of nine rigs we are currently operating on behalf of purchasers of our Delaware Basin assets in the Permian Basin). Our budget reflects sharp reductions in our natural gas drilling activities, from 50 rigs at the beginning of 2012 to an average of 9 rigs in the fourth quarter of 2012. The Current Period drilling and completion expenditures also reflected significant well completion costs for natural gas wells that had been drilled in prior periods. These completions, which we expect will represent more than 50% of all natural gas wells we complete during 2012, enabled us to hold by production the related leasehold according to the terms of our leases. For 2013, we are budgeting $5.750 - $6.250 billion for drilling and completion capital expenditures, net of drilling and completion carries, and $500 million for new leasehold expenditures, excluding reimbursements for unproved leasehold from our joint venture partners. We anticipate receiving approximately $100 million in reimbursements for unproved leasehold from our joint venture partners in 2013.
Approximately 75% of our leasehold acquisition costs during the Current Period were focused on adding acreage in the Utica, Marcellus and Mid-Continent plays. As described above, we anticipate significantly lower leasehold spending in the remainder of 2012 and 2013. Having captured what we believe are the most promising areas of our core plays, we have now shifted our focus to developing these assets.
Capital expenditures related to our midstream, oilfield services and other assets were approximately $2.295 billion during the Current Period and are projected to be $2.8 - $3.1 billion and $850 million - $1.1 billion in 2012 and 2013, respectively. We estimate that the divestiture of our midstream business, as discussed in Planned Sales below, will enable us to reduce previously budgeted capital expenditures by approximately $1.0 - $1.250 billion in 2013 and approximately $3.0 billion over the three years ending 2015.
Through the vertical integration of our oilfield services business and as operator of a substantial portion of our natural gas and oil properties under development, we have significant control and flexibility over the development plan and the associated timing, enabling us to expeditiously reduce at least a portion of our capital spending if needed. If our access to funds from planned asset sales or from other sources were limited, however, our ability to develop and replace our reserves could be reduced. Management and the board of directors are currently reviewing operational plans for 2013 and beyond, which could result in changes to the Company's drilling activity and projected production levels in 2013.
Recent Sales
An essential part of our business strategy in 2012 and 2013 is using the proceeds from sales to reduce our indebtedness and to fund the capital expenditures needed to transition from a natural gas-focused drilling program to a liquids-focused drilling program. Below we describe transactions completed in 2012 and the continuing benefits of our joint ventures which were completed prior to 2012.
Asset Sales
Permian Basin. We sold the vast majority of our Permian Basin assets, representing approximately 6% of our total proved reserves as of June 30, 2012 and 6% of our 2012 second quarter net production, in separate transactions in the second half of 2012. In September 2012, we sold our producing assets in the Midland Basin portion of the Permian Basin to affiliates of Houston-based EnerVest, Ltd. for proceeds of approximately $376 million in cash. In October 2012, we sold our assets in the Delaware Basin portion of the Permian Basin to SWEPI LP, a subsidiary of

Royal Dutch Shell plc (NYSE:RDS.B), and Chevron U.S.A. Inc., a subsidiary of Chevron Corporation (NYSE:CVX), and received approximately $2.715 billion in cash. An additional $466 million of consideration is subject to certain title, environmental and other standard contingencies, the majority of which we expect to receive in the next eighteen months.
In September 2012, to facilitate the sales process associated with our Permian Basin divestiture packages, we purchased the remaining reserves from our Permian Basin volumetric production payment (VPP), originally entered into in June 2010, for $313 million. The reserves purchased totaled 28 bcfe and were subsequently sold to the buyers of our Permian Basin assets described above.
Non-Core Utica Shale. In August 2012, we sold approximately 72,000 net acres of non-core leasehold in the Utica shale play in Ohio to affiliates of EnerVest for approximately $358 million in cash.
Texoma Woodford. In April 2012, we sold approximately 60,000 net acres of leasehold in the Texoma Woodford play in Bryan, Carter, Johnston and Marshall counties in Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation (NYSE:XOM), for approximately $572 million in cash. The properties included approximately 25 mmcfe per day of current net production.
Under full cost accounting rules, we account for the sale of natural gas and oil properties in the sales transactions described above as an adjustment to capitalized costs, with no recognition of gain or loss. In conjunction with the sales transactions, affiliates of our Chief Executive Officer, Aubrey K. McClendon, sold interests in the same properties and on the same terms as those that applied to the interests sold by the Company, and proceeds were paid to the sellers based on their respective ownership. These interests were acquired through the Founders Well Participation Program (FWPP), which provides Mr. McClendon a contractual right to participate and invest as a working interest owner (with up to a 2.5% working interest) in new wells drilled on the Company's leasehold through June 2014.
Sale of Investment in Chesapeake Midstream Partners, L.P.
In June 2012, we sold all of our common and subordinated units representing limited partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P. (NYSE:ACMP), and all of our limited liability company interests in the sole member of its general partner to funds affiliated with Global Infrastructure Partners (GIP) for cash proceeds of $2.0 billion. We recorded a $1.032 billion pre-tax gain associated with the transaction. Cleveland Tonkawa Financial Transaction
We formed CHK Cleveland Tonkawa, L.L.C. (CHK C-T) in March 2012 to continue development of a portion of our natural gas and oil assets in our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our corporate credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including under our indentures. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the Cleveland and Tonkawa plays covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 new net wells to be drilled on certain of our Cleveland and Tonkawa play leasehold. For further discussion, see Noncontrolling Interests in Note 6 of the notes to our condensed consolidated financial statements included in Part I, Item 1 of this report.
Volumetric Production Payment (VPP)
In March 2012, we monetized certain of our producing assets in the Anadarko Basin Granite Wash through a ten-year VPP for proceeds of approximately $744 million. The transaction included approximately 160 bcfe of proved reserves and approximately 125 mmcfe per day of net production. Chesapeake has retained drilling rights on the properties below currently producing intervals and outside of existing producing wellbores and we also retain all production beyond the specified volumes sold in the transaction. This transaction was our tenth VPP. The cash proceeds from this transaction were reflected as a reduction of natural gas and oil properties with no gain or loss recognized. Other VPPs we completed in 2007 - 2011 are detailed in Note 8 of the notes to our condensed consolidated financial statements included in Part I, Item 1 of this report.

Joint Ventures
As of September 30, 2012, we had entered into seven significant joint ventures with other leading energy companies pursuant to which we sold a portion of our leasehold, producing properties and other assets located in seven different resource plays and received cash of $7.1 billion and commitments for future drilling and completion cost sharing of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all leasing, drilling, completion, operations and marketing activities for the project. The carry obligations paid by a joint venture partner are for a specified percentage of our drilling and completion cost obligations. In addition, a joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner. We bill our joint venture partners for their drilling carry obligations at the same time we bill them and other joint working interest owners for their share of drilling costs as they are incurred. Our joint venture transactions have allowed us to recover much or all of our initial leasehold investments and reduce our ongoing capital costs in these plays. The transactions are detailed below.

                                                              Cash                              Total Cash
                 Joint           Joint                      Proceeds          Total            and Drilling        Drilling
  Primary       Venture         Venture       Interest      Received        Drilling              Carry             Carries
    Play       Partner(a)        Date           Sold       at Closing        Carries             Proceeds        Remaining(b)
                                                                                    ($ in millions)
Utica          TOT          December 2011      25.0%     $        610     $     1,422        $        2,032     $       1,249
Niobrara       CNOOC        February 2011      33.3%              570             697                 1,267               495
Eagle Ford     CNOOC        November 2010      33.3%            1,120           1,080                 2,200                 -
Barnett        TOT          January 2010       25.0%              800           1,404   (c)           2,204                 -
Marcellus      STO          November 2008      32.5%            1,250           2,125                 3,375                 -
Fayetteville   BP           September 2008     25.0%            1,100             800                 1,900                 -
Haynesville
& Bossier      PXP          July 2008          20.0%            1,650           1,508   (d)           3,158                 -
                                                         $      7,100     $     9,036        $       16,136     $       1,744


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