On June 6, 2008, the Company entered into three crude oil price swaps to hedge a portion of its estimated crude oil production for the calendar years 2010, 2011 and 2012.
Additionally, on July 25, 2008, the Company entered into two crude oil price swaps to hedge a portion of its estimated crude oil production for the calendar years 2008 and 2009. The contracts are for 49,000 Bbls per month for the remainder of 2008 (August through December) at a fixed price of $124.35 per Bbl, and 29,000 Bbls per month for calendar year 2009 at a fixed price of $125.10 per Bbl. The Company has not designated these derivative instruments as cash flow hedges. Mark-to-market adjustments related to these derivative instruments will be recorded each period to (Gain) loss on derivatives not designated as hedges. Subsequent events
Henry Acquisition. On July 31, 2008, we closed the acquisition of Henry Petroleum LP and certain affiliated entities (collectively "Henry") (the "Acquisition"). Cash paid at closing totaled approximately $560 million. We financed the Acquisition with proceeds raised from a $250.0 million private placement of 8.3 million shares of our common stock, together with funds available under a new amended and restated senior credit facility (the "Senior Credit Facility"), as further described below. After the closing of the Henry transaction and the additional interests acquired concurrently as described below, we have approximately $285 million of availability under the Senior Credit Facility.
In connection with the Acquisition, we also purchased certain additional non-operated rights and interests in Henry's oil and gas properties from certain persons affiliated with Henry (such transactions, collectively, the "Along-side Transactions") for aggregate cash consideration of approximately $28.0 million.
The following table shows the sources and uses of funds for the above referenced transactions on July 31, 2008:

            Sources of Funds:
            Proceeds from Issuance of Common Shares          $ 250,000
            Initial Borrowing under Senior Credit Facility     675,000

            Total Sources of Funds                           $ 925,000


            Uses of Funds:
            Purchase of Henry Equity Interests               $ 536,830
            Repay 1st Lien Credit Facility                     194,389
            Repay 2nd Lien Credit Facility                     113,189
            Purchase of Along-side Property Interests           28,039
            Fees and Expenses                                   24,829
            Working Capital and General Corporate Purposes      27,724

            Total uses of Funds                              $ 925,000

Common Stock Purchase Agreement. On June 5, 2008, we also entered into a Common Stock Purchase Agreement (the "Purchase Agreement") with certain unaffiliated third-party investors (the "Purchasers") to sell approximately 8.3 million shares of our common stock in a private placement (the "Private Placement") for aggregate cash consideration of approximately $250.0 million, for a negotiated price of $30.11 per share. The Private Placement closed simultaneously with the Acquisition on July 31, 2008.
The closing of the Private Placement was subject to customary closing conditions, as well as certain other conditions, including (i) the closing of the Acquisition and (ii) the execution by us and the Purchasers of a registration rights agreement that will require us to file a shelf registration statement for the benefit of the Purchasers within 60 days after the closing of the Private Placement.
The Private Placement is being made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, pursuant to
Section 4(2) thereof.
Amended and Restated Credit Facility. As of July 31, 2008, we amended and restated our Senior Credit Facility in various respects including, increasing the borrowing base to $960 million, subject to semiannual redetermination, and extending the maturity date from February 24, 2011 to July 31, 2013. The initial borrowing under the Senior Credit Facility was $675 million. We paid an arrangement fee of $14.4 million

at the date of closing of the Senior Credit Facility. This fee is being amortized to Interest expense over the remaining five year term of the facility beginning in August 2008.
Advances on the Senior Credit Facility bear interest, at our option, based on
(a) the prime rate of JPMorgan Chase Bank ("JPM Prime Rate") (5.00 percent at July 31, 2008) or (b) a Eurodollar rate (substantially equal to the London Interbank Offered Rate). The interest rates of Eurodollar rate advances and JPM Prime Rate advances vary, with interest margins ranging from 125 - 275 basis points and 0 - 125 basis points, respectively, per annum depending on the balance outstanding. We pay commitment fees on the unused portion of the available borrowing base ranging from 25 - 50 basis points per annum. The Senior Credit Facility also includes a same-day advance facility under which we may borrow funds on a daily basis from the 1st Lien Banks' administrative agent. Advances made on this same-day basis cannot exceed $25 million and the maturity dates cannot exceed fourteen days. The interest rate on this facility is the JPM Prime Rate plus the applicable interest margin. Our obligations under the Senior Credit Facility are secured by a first lien on substantially all of our oil and gas properties. In addition, all of our subsidiaries are guarantors, and all subsidiary general partner, limited partner and membership interests owned by us have been pledged to secure borrowings under the Senior Credit Facility. The credit agreement contains various restrictive covenants and compliance requirements which include (a) maintenance of certain financial ratios (i) maintenance of a quarterly ratio of total debt to consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and other noncash income and expenses no greater than 4.0 to 1.0, and (ii) maintenance of a ratio of current assets to current liabilities, excluding noncash assets and liabilities related to financial derivatives and asset retirement obligations, to be no less than 1.0 to 1.0; (b) limits on the incurrence of additional indebtedness and certain types of liens; (c) restrictions as to merger and sale or transfer of assets; and (d) a restriction on the payment of cash dividends.

Results of operations of Concho Resources Inc.

The following table presents selected financial and operating information of Concho Resources Inc. for the three and six months ended June 30, 2008 and 2007:

                                                     Three months ended                     Six months ended
                                                          June 30,                              June 30,
                                                   2008               2007              2008               2007
(in thousands, except price data)                        (unaudited)                          (unaudited)

Oil sales                                       $  95,408          $ 43,096          $ 171,226          $  82,467
Natural gas sales                                  41,975            23,007             72,868             43,982

Total operating revenues                          137,383            66,103            244,094            126,449
Operating costs and expenses                       54,942            46,324            103,147             88,262
Loss on derivatives not designated as
hedges                                            102,456                 -            119,634                  -
Interest, net and other revenue                     3,574             9,866              8,169             20,276

Income (loss) before income taxes                 (23,589 )           9,913             13,144             17,911
Income tax benefit (expense)                        9,169            (3,988 )           (5,199 )           (7,363 )

Net income (loss)                               $ (14,420 )        $  5,925          $   7,945          $  10,548


Production volumes:
Oil (MBbl)                                            899               730              1,786              1,438
Natural gas (MMcf)                                  3,346             2,953              6,451              5,905
Natural gas equivalent (MMcfe)                      8,740             7,330             17,167             14,536
Average prices:
Oil, without hedges ($/Bbl)                     $  121.00          $  60.15          $  107.39          $   57.16
Oil, with hedges ($/Bbl)                        $  106.13          $  59.07          $   95.87          $   57.33
Natural gas, without hedges ($/Mcf)             $   12.52          $   7.77          $   11.33          $    7.42
Natural gas, with hedges ($/Mcf)                $   12.54          $   7.79          $   11.30          $    7.45
Natural gas equivalent, without hedges
($/Mcfe)                                        $   17.24          $   9.12          $   15.43          $    8.67
Natural gas equivalent, with hedges
($/Mcfe)                                        $   15.72          $   9.02          $   14.22          $    8.70



Bbl   - Barrel

MBbl  - Thousand
        Barrels

Mcf   - Thousand
        cubic feet

MMcf  - Million
        cubic feet

Mcfe  - Thousand
        cubic feet
        of natural
        gas
        equivalent
        (computed on
        an energy
        equivalent
        basis of one
        Bbl equals
        six Mcf)

MMcfe - Million
cubic feet
of natural
gas
equivalent
(computed on
an energy
equivalent
basis of one
Bbl equals
six Mcf)

Three months ended June 30, 2008, compared to three months ended June 30, 2007 Oil and gas revenues. Revenue from oil and gas operations was $137.4 million for the three months ended June 30, 2008, an increase of $71.3 million (108%) from $66.1 million for the three months ended June 30, 2007. This increase was primarily because of increased production due to successful drilling efforts during 2008 coupled with substantial increases in realized oil and gas prices. In addition:
• average realized oil prices (after giving effect to hedging activities) were $106.13 per Bbl during the three months ended June 30, 2008, an increase of 80% from $59.07 per Bbl during the three months ended June 30, 2007;
• total oil production was 899 MBbl for the three months ended June 30, 2008, an increase of 169 MBbl (23%) from 730 MBbl for the three months ended June 30, 2007;
• average realized natural gas prices (after giving effect to hedging activities) were $12.54 per Mcf during the three months ended June 30, 2008, an increase of 61% from $7.79 per Mcf during the three months ended June 30, 2007;
• total natural gas production was 3,346 MMcf for the three months ended June 30, 2008, an increase of 393 MMcf (13%) from 2,953 MMcf for the three months ended June 30, 2007;
• average realized natural gas equivalent prices (after giving effect to hedging activities) were $15.72 per Mcfe during the three months ended June 30, 2008, an increase of 74% from $9.02 per Mcfe during the three months ended June 30, 2007; and
• total production was 8,740 MMcfe for the three months ended June 30, 2008, an increase of 1,410 MMcfe (19%) from 7,330 MMcfe for the three months ended June 30, 2007. See discussion in "-Recent events" about 2007 and 2008 production interruptions due to plant and refinery shut-downs. Hedging activities. The oil and gas prices that we report are based on the market price received for the commodities adjusted to give effect to the results of our cash flow hedging activities. We utilize commodity derivative instruments (swaps and zero cost collar option contracts) in order to (1) reduce the effect of the volatility of price changes on the commodities we produce and sell,
(2) support our annual capital budgeting and expenditure plans and (3) lock-in commodity prices to protect economics related to certain capital projects. The following is a summary of the effects of commodity hedges for the three months ended June 30, 2008 and 2007:

                                                         Crude Oil Hedges                          Natural Gas Hedges
                                                        Three months ended                         Three months ended
                                                             June 30,                                   June 30,
                                                     2008                  2007                2008                 2007
                                                            (unaudited)                               (unaudited)
Hedging revenue increase (decrease)             $ (13,367,000 )        $ (783,000 )        $    74,000          $    49,000
Hedged volumes (Bbls and MMBtus,
respectively)                                         236,000             268,000            1,228,000            1,647,000
Hedged revenue increase (decrease) per
hedged volume                                   $      (56.64 )        $    (2.92 )        $      0.06          $      0.03

During the three months ended June 30, 2008, our commodity price hedges decreased oil revenues by $13.4 million ($14.87 per Bbl). During the three months ended June 30, 2007, our commodity price hedges decreased oil revenues by $0.8 million ($1.07 per Bbl). The effect of the commodity price hedges in decreasing oil revenues during the three months ended June 30, 2008 compared to their effect of decreasing oil revenues during the three months ended June 30, 2007 was the result of (1) a higher average market price of NYMEX crude oil of $124.28 per Bbl in 2008 as compared to $65.08 per Bbl in 2007 and (2) the greater price difference between NYMEX and the weighted average hedge price in 2008 as compared to 2007, partially offset by a lower amount of hedged volumes of 236,000 Bbls in 2008 as compared to 268,000 Bbls in 2007.
During the three months ended June 30, 2008, our commodity price hedges increased gas revenues by $0.07 million ($0.02 per Mcf) as a result of the amount reclassified from AOCI into natural gas revenues from cash flow hedges that were dedesignated as of June 30, 2007. Cash settlements for these dedesignated natural gas contracts are being recorded to (Gain) loss on derivatives not designated as hedges. During the three months ended June 30, 2007, our commodity price hedges increased gas revenues by $0.05 million ($0.02 per Mcf) as a result of the price difference between the market reference price of natural gas and the commodity contract price.

in 2008 as compared to settlements in 2007, partially offset by a lower amount of hedged volumes of 1,228,000 MMBtus in 2008 as compared to 1,647,000 MMBtus in 2007.
Production expenses. Production expenses (including production taxes) were $22.0 million ($2.51 per Mcfe) for the three months ended June 30, 2008, an increase of $9.8 million (80%) from $12.2 million ($1.66 per Mcfe) for the three months ended June 30, 2007. The increase in production expenses is due to: (1) production expenses associated with new wells that were successfully completed in 2008 as a result of our drilling activities and (2) an increase in production taxes as discussed below. Lease operating expenses and workover costs comprised approximately 45% and 57% of production expenses for the three months ended June 30, 2008 and 2007, respectively. These costs per unit of production were $1.14 per Mcfe during the three months ended June 30, 2008, an increase of 20% from $0.95 per Mcfe during the three months ended June 30, 2007. Lease operating expenses include ad valorem taxes that are affected by commodity price changes and ad valorem tax rates. Ad valorem taxes were approximately 5% of lease operating expenses for the three months ended June 30, 2008 and 2007.
The secondary component of production expenses is production taxes, which is directly related to commodity price changes. These costs comprised approximately 55% and 43% of production expenses during the three months ended June 30, 2008 and 2007, respectively. Production taxes per unit of production were $1.38 per Mcfe during the three months ended June 30, 2008, an increase of 92% from $0.72 per Mcfe during the three months ended June 30, 2007. This increase was primarily due to an increase in average natural gas equivalent prices we received.
Exploration and abandonments expense. The following table provides a breakdown of our exploration and abandonments expense for the three months ended June 30, 2008 and 2007:

                                                     Three months ended
                                                          June 30,
                                                     2008          2007
             (in thousands)                             (unaudited)

             Geological and geophysical            $   424       $   225
             Exploratory dry holes                     (19 )       5,635
             Leasehold abandonments and other          318             4

             Total exploration and abandonments    $   723       $ 5,864

Our geological and geophysical expense, which primarily consists of the costs of acquiring and processing seismic data, geophysical data and core analysis, during the three months ended June 30, 2008 was $0.4 million, an increase of $0.2 million from $0.2 million for the three months ended June 30, 2007. This increase is primarily attributable to a comprehensive seismic survey on our New Mexico shelf properties which was initiated in December 2007.
Our exploratory dry holes expense during the three months ended June 30, 2007 was primarily attributable to three operated exploratory wells that were unsuccessful. The costs associated with one of these wells drilled in the Western Delaware Basin in Culberson County, Texas approximated $2.8 million. Another of these wells, which was drilled in the Southeastern New Mexico Basin in Lea County, New Mexico, had costs of approximately $2.0 million. An additional $0.8 million was charged to exploratory dry hole costs relative to a target zone in the third of these wells in the Southeastern New Mexico Basin in Eddy County, New Mexico which was determined to be dry. This well was completed in a shallower zone which was found to be productive.
For the three months ended June 30, 2008, we recorded $0.3 million of leasehold abandonments, which are primarily related to prospects in Chaves County, New Mexico and Crane County, Texas. We had minimal leasehold abandonments during the three months ended June 30, 2007.
Depreciation and depletion expense. Depreciation and depletion expense was $22.0 million ($2.52 per Mcfe), including $21.6 million associated with oil and gas properties ($2.47 per Mcfe), for the three months ended June 30, 2008, an increase of $4.4 million from $17.6 million ($2.40 per Mcfe), including $17.4 million associated with oil and gas properties ($2.37 per Mcfe), for the three months ended June 30, 2007. The increase in depreciation and depletion expense was primarily due to capitalized costs associated with new wells that were successfully completed in 2007 and 2008 as a result of our drilling activities. Despite an increase in total proved reserves, the depreciation and depletion rate per Mcfe increased from the three months ended June 30, 2007 to the three months ended June 30, 2008, due to an increase in capitalized costs as a result of our successful development and exploratory drilling program. The crude oil price utilized for our estimate of proved oil and gas reserves was $136.50 as of June 30, 2008, an increase of

$69.25 (103%) from $67.25 as of June 30, 2007. The natural gas price utilized for our estimate of proved oil and gas reserves was $13.10 as of June 30, 2008, an increase of $6.30 (93%) from $6.80 as of June 30, 2007.
Impairment of oil and gas properties. In accordance with SFAS No. 144, we review our long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting. As a result of this review of the recoverability of the carrying value of our assets during the three months ended June 30, 2008, we recognized a non-cash charge against earnings of $0.1 million, which was comprised primarily of a well located in Lea County, New Mexico. For the three months ended June 30, 2007, we recognized a non-cash charge against earnings of $2.1 million, primarily related to a well drilled on acreage in Schleicher County, Texas.
Contract drilling fees - stacked rigs. As discussed in our Annual Report on Form 10-K for the year ended December 31, 2007, we determined in January 2007 to reduce our drilling activities for the first three months of 2007. As a result, we recorded an expense during the three months ended June 30, 2007 of approximately $0.9 million for contract drilling fees related to stacked rigs subject to daywork drilling contracts with two drilling contractors. We resumed the majority of our planned drilling activities in April 2007 and all planned drilling activities in June 2007. These costs were minimized during the first six months of 2007 as one contractor secured work for a rig for 71 days during that period and charged us only the difference between the then-current operating day rate pursuant to the contract and the lower operating day rate received from the new customer.
General and administrative expenses. General and administrative expenses were $8.6 million ($0.98 per Mcfe) for the three months ended June 30, 2008, an increase of $1.0 million (13%) from $7.6 million ($1.04 per Mcfe) for the three months ended June 30, 2007. Included in general and administrative expense was non-cash stock-based compensation of $1.7 million during the three months ended June 30, 2008 and $1.1 million during the three months ended June 30, 2007. General and administrative expenses, excluding non-cash stock-based compensation, ("Net general expense") were $6.9 million ($0.78 per Mcfe) for the three months ended June 30, 2008, an increase of $0.4 million (6%) from $6.5 million ($0.89 per Mcfe) for the three months ended June 30, 2007. The increase in Net general expenses during the three months ended June 30, 2008 was primarily due to an increase in the number of employees and related personnel expenses. . . .