exv99w1

Exhibit 99.1

SandRidge Energy, Inc. Reports Operational and Financial Results for Second Quarter and First Six Months of 2008

Oklahoma City, Oklahoma, August 7, 2008 — SandRidge Energy, Inc. (NYSE: SD) today announced operational and financial results for the 2008 second quarter and six months ended June 30, 2008. Key results were:

Production and Exploration Highlights:

West Texas Overthrust (“WTO”)

	•		Piñon field estimated proved, possible and probable (“3-P”) net reserves increased to 5.1 Tcfe from 4.1 Tcfe during the first six months of 2008.

	•		3-D seismic and well data in Piñon field confirmed production from three major thrust faults (Dugout Creek, Warwick and Frog Creek) that extend across the WTO.

	•		Eleven initial sweet (0% to 4% CO₂) 1^st Caballos completions in east Piñon combined to add 91 Bcfe gross proved developed producing (“PDP”) reserves.

	•		Leasehold position in the WTO increased to approximately 610,000 net acres from approximately 547,000 net acres at March 31, 2008.

Corporate

	•		Initial 2009 net production guidance is 135.0 Bcfe, an increase of 35% over expected 2008 production.

	•		2008 net production guidance of 100.0 Bcfe remained unchanged despite net production loss of 25.0 MMcfe per day, or approximately 5.0 Bcfe, due to the Grey Ranch Plant fire in Pecos County, Texas and major well work in the Texas Gulf Coast. Current production is approximately 295.0 MMcfe per day.

	•		2008 capital expenditure guidance increased to $2.0 billion from $1.5 billion due to ramp up of rigs for exploration and development activities. Initial 2009 capital expenditure guidance is $2.0 billion.

	•		On June 29, 2008, SandRidge and a subsidiary of Occidental Petroleum Corporation (“Occidental”) entered into a construction agreement and a 30-year treating agreement to build and operate an 800.0 MMcfe per day CO₂ extraction plant (“Century Plant”) in Pecos County, Texas. The incremental capacity of the Century Plant will enable the company to treat 1.1 Bcfe per day of high CO₂ gas, resulting in an estimated 385.0 MMcfe per day of gross methane production from the 1^st Caballosreservoir by the end of 2011.

Second Quarter Highlights:

	•		Natural gas and crude oil production of 25.4 Bcfe (280 MMcfed), an increase of 11% compared to first quarter 2008 and 70% compared to second quarter 2007

	•		Proved reserves at quarter end of 1.918 Tcfe, an increase of 13% from March 31, 2008 and 63% from June 30, 2007; drillbit reserve replacement and all-in reserve replacement rates of 998%

	•		Drilling finding costs and all-in finding costs of $1.37 and $1.80 per Mcfe, respectively

	•		Net loss applicable to common stockholders of $27.0 million (including unrealized non-cash losses of $101.8 million due to mark-to-market accounting on open derivative contracts), or ($0.17) per share, versus income available to common stockholders of $22.3 million, or $0.21 per share, in second quarter 2007

	•		Adjusted net income available to common stockholders ^(a)of $33.1 million, or $0.21 per share, compared to adjusted net loss applicable to common stockholders of $2.3 million, or ($0.02) per share, in second quarter 2007

	•		Operating cash flow ^(b) of $145.1 million, an increase of 1% from first quarter 2008 and 120% from second quarter 2007

•

Adjusted EBITDA ^(c) of $183.0 million, an increase of 9% from first quarter 2008 and 107% from second quarter 2007

First Six Months Highlights:

	•		Natural gas and crude oil production of 48.3 Bcfe (265 MMcfed), an increase of 74% compared to production of 27.7 Bcfe in the first six months of 2007

	•		Proved reserves at June 30, 2008 of 1.918 Tcfe, an increase of 27% from December 31, 2007; drillbit reserve replacement and all-in reserve replacement rates of 950% and 953%, respectively

	•		Drilling finding costs and all-in finding costs of $1.43 and $1.77 per Mcfe, respectively

	•		Net loss applicable to common stockholders of $93.2 million (including unrealized non-cash losses of $245.9 million due to mark-to-market accounting on open derivative contracts), or ($0.63) per share, versus $6.2 million, or ($0.06) per share, in the first six months of 2007

	•		Adjusted net income available to common stockholders ^(a)of $60.0 million, or $0.41 per share, compared to adjusted net loss applicable to common stockholders of $16.6 million, or ($0.17) per share, in the first six months of 2007

	•		Operating cash flow ^(b) of $288.4 million, an increase of 155% from the same period in 2007

	•		Adjusted EBITDA ^(c) of $350.6 million, an increase of 123% from the same period in 2007

Presentation slides to be viewed in conjunction with certain of the above Production and Exploration Highlights are available on the company’s website, www.sandridgeenergy.com, under Investor Relations/Events.

(a)		Adjusted net income available (loss applicable) to common stockholders is income available (loss applicable) to common stockholders, excluding the unrealized impact of derivative contracts, net of tax. See Non-GAAP Financial Measures.

(b)		Operating cash flow is net cash provided by (used in) operating activities before changes in operating assets and liabilities. See Non-GAAP Financial Measures.

(c)		Adjusted EBITDA is earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items. See Non-GAAP Financial Measures.

Operational Highlights


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Production:
Natural gas (MMcf)		21,715			11,843			40,888			22,292
Crude oil (MBbl)⁽¹⁾		620			513			1,231			906
Natural gas equivalent (MMcfe)		25,435			14,921			48,274			27,728
Daily Production (MMcfed)		280			164			265			153

Average price per unit:
Realized natural gas price per Mcf — as reported	$	10.22		$	7.16		$	9.11		$	6.90
Realized impact of derivatives per Mcf		(2.29	)		0.06			(1.00	)		(0.04	)

Net realized price per Mcf	$	7.93		$	7.22		$	8.11		$	6.86


Realized crude oil price per barrel — as reported ⁽¹⁾	$	113.12		$	61.34		$	101.55		$	58.18
Realized impact of derivatives per barrel ⁽¹⁾		(13.15	)		—			(7.81	)		—

Net realized price per barrel ⁽¹⁾	$	99.97		$	61.34		$	93.74		$	58.18


Realized price per Mcfe — as reported	$	11.49		$	7.79		$	10.31		$	7.45

Net realized price per Mcfe — including impact of derivatives per Mcfe	$	9.21		$	7.84		$	9.26		$	7.42


Average cost per Mcfe:
Lease operating	$	1.58		$	1.81		$	1.54		$	1.77
Production taxes		0.53			0.33			0.47			0.29
General and administrative:
General and administrative, excluding stock-based compensation		0.87			0.78			0.83			0.83
Stock-based compensation		0.16			0.08			0.15			0.08
Depletion		2.84			2.55			2.85			2.55

Lease operating cost by region per Mcfe:
Offshore operations	$	4.26		$	2.75		$	3.52		$	3.23
Tertiary recovery operations		9.04			9.00			11.02			11.72
Excluding offshore and tertiary recovery		1.36			1.60			1.34			1.48

Earnings per share:
Basic and diluted (loss) income per share (applicable) available to common stockholders	$	(0.17	)	$	0.21		$	(0.63	)	$	(0.06	)
Basic and diluted adjusted net (loss) income per share (applicable) available to common stockholders		0.21			(0.02	)		0.41			(0.17	)

Weighted average number of common shares outstanding (thousands)
Basic		155,204			107,524			148,124			100,025
Diluted		155,204			108,602			148,124			100,025


⁽¹⁾		Includes NGLs

Operational Updates

SandRidge owned working interests in 1,884 producing wells at June 30, 2008 compared to 1,469 producing wells at June 30, 2007. The company had an average of 41 rigs operating on its properties throughout the second quarter of 2008. The following is an operational update for each of the company’s key areas:

West Texas Overthrust (WTO): The company averaged 31 rigs running in the WTO during second quarter 2008 compared to an average of 25 rigs during the same period of 2007. There are currently 34 rigs active in the WTO. The company plans to ramp up drilling activities and expects to exit 2008 with 40 active rigs in this area. Two of the six additional rigs will be dedicated to exploration drilling, bringing the total rig count dedicated to exploration drilling within the WTO to 7 rigs from the current 5 rigs. The number of wells completed and brought on production also increased during second quarter 2008 to 44 gross (41 net) from a total of 28 gross (26 net) during second quarter 2007. At June 30, 2008, the company owned and operated 587 gross (548 net) wells in the WTO. SandRidge also continued its 3-D seismic program during second quarter 2008, acquiring data over 275 square miles and bringing the total area acquired to date by the program to 850 square miles.

East Texas: The average number of rigs operating on the company’s properties in East Texas during second quarter 2008 increased to five from an average of four during second quarter 2007. Correspondingly, the number of wells completed and brought on production in East Texas during second quarter 2008 also increased to 16 gross (15 net) from 9 gross (7 net) during the same period in 2007. At June 30, 2008, the company owned 215 gross (198 net) wells in East Texas. SandRidge recently

announced its intent to sell its East Texas and North Louisiana properties, as described below under Subsequent Events.

Mid-Continent: The company increased the number of rigs drilling on its prospects located in Oklahoma during second quarter 2008 to three from one rig during the same period of 2007. A total of 21 gross (17 net) Oklahoma wells were completed and brought on production in second quarter 2008 compared to 2 wells brought on production during second quarter 2007. At June 30, 2008, the company owned 397 gross (165 net) wells in the Mid-Continent area. The company plans to increase drilling in this area due to success established over the last 18 months. The company’s net production has increased to 25.0 MMcfe per day from 7.0 MMcfe per day during that time period from limited capital expenditures.

Recent Events

Exchange of Senior Term Loans. In May 2008, the company completed an offer to exchange the senior term loans for senior unsecured notes with registration rights, as required under the senior term loan credit agreement. The company issued $650.0 million of 8.625% Senior Notes due 2015 in exchange for an equal outstanding principal amount of its fixed rate term loan and $350.0 million of Senior Floating Rate Notes due 2014 in exchange for an equal outstanding principal amount of its variable rate term loan. The newly issued senior notes have terms that are substantially identical to those of the exchanged senior term loans, except that the senior notes have been issued with registration rights. The company expects to complete registration of these notes by late third quarter 2008, subject to Securities and Exchange Commission review.

Conversion of Redeemable Convertible Preferred Stock. In May 2008, the company converted the remaining outstanding 1,844,464 shares of its redeemable convertible preferred stock into 18,810,260 shares of common stock as permitted under the terms of the redeemable convertible preferred stock.

Sale of Colorado Assets. The company completed the sale of all its assets located in the Piceance Basin of Colorado in May 2008. Net proceeds to the company were approximately $147.2 million after closing adjustments. Assets sold included undeveloped acreage, working interests in wells, gathering and compression systems and other facilities related to the wells.

Issuance of 8.0% Senior Notes. In May 2008, the company issued $750.0 million in 8.0% Senior Notes due 2018. A portion of the $735.0 million net proceeds received from the offering was used to repay the total balance outstanding on the company’s senior credit facility of $478.0 million. The remaining proceeds are expected to be used to fund a portion of the company’s 2008 capital expenditures budget.

Change in Borrowing Base. As a result of the company’s May 2008 issuance of $750.0 million in senior notes, as described above, the borrowing base of its senior credit facility was reduced to $1.1 billion from $1.2 billion. The total committed amount of the senior credit facility remains at $1.75 billion.

Piñon Field 3-D Seismic. A better understanding of the subsurface picture in the Piñon field is a key element to successful exploration of the company’s 610,000 net acre position in the WTO. Part of that understanding is obtained via 3-D seismic data, which became available over the Piñon field in May 2008. This 3-D seismic along with data from approximately 600 wells drilled to date indicate that the Piñon field produces commercially from at least 3 major thrust fault systems (Dugout Creek, Warwick, and Frog Creek) and that these major thrust faults extend across the entire WTO. Incorporating the regional thrust fault theory with well information and geology, the company began integrating the Piñon 3-D seismic data with the 3-D seismic data from 15 miles to 30 miles away within the South Sabino and Big Canyon exploration areas. Results from the Piñon 3-D seismic are already being realized. The company drilled the West Ranch 42-2 well in a previously untested fault block of approximately 3,400 acres in the southeast portion of the Piñon field in the Warwick thrust. The West Ranch 42-2, drilled to a total depth of 7,430 feet and encountered several packages of chert sections, including the 1^st Caballos from 3,500 feet to 7,300 feet. Initial tests in the 1^st Caballos at approximately 7,200 feet resulted in sweet gas production at rates over 1.0 MMcf per day. Other chert zones in the well are currently being tested. The West Ranch 42-2 well further expands the area of 1^st Caballos sweet production.

Production Shut-Ins. The company experienced a fire at its Grey Ranch Plant located in Pecos County, Texas on June 27, 2008. While there were no injuries, the company believes that the plant will be shut down for a minimum of 90 days from the date of the fire for repairs. Loss to the company as a result of the fire is approximately 16.5 MMcf per day of net methane production. In the Gulf Coast, an additional 8.5 MMcfe per day net production was shut in during May 2008 due to major well work.

Century Plant Construction and Gas Treating and CO₂ Delivery Agreements. In June 2008, SandRidge entered into an agreement with Occidental to construct the Century Plant located in Pecos County, Texas and associated compression and pipeline facilities for a contract price of $800.0 million. SandRidge will construct the Century Plant and associated facilities. Occidental will reimburse SandRidge an amount equal to at least 100% of the contract price (including any subsequently agreed-upon revisions) through periodic payments based upon a percentage of project completion methodology. Upon start-up, Occidental will own and operate the Century Plant and associated facilities. Under a thirty-year agreement, SandRidge is committed to deliver high CO₂gas and Occidental is committed to accept and treat the high CO₂ gas. Occidental will retain substantially all CO₂ extracted at the Century Plant and SandRidge’s other existing CO₂extraction plants. SandRidge will retain all methane from the Century Plant and SandRidge’s other existing plants. With the Century Plant and other existing plants, SandRidge expects to be able to produce up to 700.0 MMcf per day of 65% CO₂ gas by third quarter 2010 and 1.1 Bcf per day by third quarter 2011. Projected methane production from high CO₂ gas net (royalties, fuel and unaccounted losses) to SandRidge is expected to be approximately 170.0 MMcfe per day by third quarter 2010 and 270.0 MMcfe per day by fourth quarter 2011.

Subsequent Events

Intent to Sell East Texas and North Louisiana Properties. In July 2008, the company announced its intent to offer certain properties for sale and to retain Deutsche Bank Securities, Inc. and Tristone Capital, LLC to assist in the marketing efforts. Assets subject to the potential sale include properties with associated current net production of nearly 50 MMcfe per day from the Cotton Valley Sandstone and over 1,000 Cotton Valley locations remaining to be drilled as well as Haynesville/Bossier Shale potential.

Property Acquisitions. During July 2008, the company purchased land, minerals, developed and undeveloped leasehold and interests in producing properties through various transactions at an aggregate purchase price of $67.6 million.

Change in Mark-to-Market on Commodity Derivatives. Due to recent changes in commodity prices, the change in the fair value of the company’s derivative contracts from June 30, 2008 to July 31, 2008 would result in an unrealized valuation gain of $213.5 million.

Second Quarter 2008 Results

Revenue: Total revenue rose 138% to $378.1 million for the three months ended June 30, 2008 from $159.1 million in the same period in 2007 primarily due to a $175.9 million increase in natural gas and crude oil sales and a $43.6 million increase in midstream gas services revenues.

Total natural gas and crude oil revenues increased to $292.1 million for the three months ended June 30, 2008 compared to $116.3 million for the same period in 2007, primarily as a result of increases in natural gas and crude oil production volumes and prices received for the company’s production. Total natural gas production increased 83% to 21.7 Bcf in second quarter 2008 compared to 11.8 Bcf in the same period in 2007, while crude oil production increased 21% to 620 MBbls in second quarter 2008 from 513 MBbls in second quarter 2007. The growth in production was due to successful drilling in the WTO and the company’s increased working interest in 2008 in the WTO compared to the same period in 2007. The average price received, excluding the impact of derivative contract settlements, for natural gas sales increased 43% in the three months ended June 30, 2008 to $10.22 per Mcf compared to $7.16 per Mcf in the same period in 2007. The average price received, excluding the impact of derivative contract settlements, for crude oil production increased 84%, or $51.78 per barrel, to $113.12 per barrel during second quarter 2008 from $61.34 per barrel during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for natural gas for second quarter 2008 was $7.93 per Mcf compared to $7.22 per Mcf during the same period in 2007. Including the impact of derivative contract settlements, the effective price received for crude oil for second quarter 2008 was $99.97 per barrel. The company’s derivative contracts had no impact on effective oil prices during second quarter 2007.

Drilling and services revenue remained relatively unchanged at $12.0 million for the three months ended June 30, 2008 compared to $12.3 million for the same period in 2007.

Midstream and marketing revenue increased $43.6 million, or 168%, to $69.5 million in the three-month period ended June 30, 2008 compared to $25.9 million in the three-month period ended June 30, 2007. The change is due to an increase in the production volumes transported and marketed during the three months ended June 30, 2008 compared to the same period in 2007 for third parties with ownership in the company’s wells or ownership in other wells connected to the company’s gathering systems. Higher natural gas prices prevalent during second quarter 2008 compared to the same period in 2007 also contributed to the increase.

Other revenue, which is generated primarily by the company’s CO₂ gathering and sales operations, was $4.5 million for the three months ended June 30, 2008 as well as for the same period in 2007.

Operating Costs and Expenses: Total operating costs and expenses increased to $389.8 million for the three months ended June 30, 2008 compared to $83.9 million for the same period in 2007 due to $159.8 million in realized and unrealized losses on derivative contracts as well as increases in production-related costs, general and administrative expenses as a result of an increase in corporate staff, and depreciation, depletion and amortization. Excluding the effects of gains and losses on derivative contracts, total operating costs for second quarter 2008 and 2007 were $230.1 million and $123.1 million, respectively.

Production expenses include the costs associated with production activities, including, but not limited to, lease operating expense and processing costs. Production expenses increased $13.2 million for second quarter 2008 compared to the same period in 2007 primarily due to an increase in the number of wells in which the company owns a working interest. Production taxes rose $8.5 million, or 171%, to $13.5 million due to increases in natural gas production and prices received for production during the three months ended June 30, 2008.

Drilling and services expenses decreased slightly to $5.1 million for the three months ended June 30, 2008 from $5.3 million in the same period in 2007.

Midstream and marketing expenses increased $41.4 million, or 178%, to $64.7 million due to larger third-party production volumes transported and marketed during the three months ended June 30, 2008 compared to the same period in 2007.

Depreciation, depletion and amortization (“DD&A”) for natural gas and crude oil properties increased to $72.3 million for the three months ended June 30, 2008 from $38.0 million in the same period in 2007. DD&A per Mcfe increased $0.29 to $2.84 in second quarter 2008 from $2.55 in the comparable period in 2007. The increase was primarily attributable to an increase in depreciable properties, higher future development costs and increased production. Production increased 70% to 25.4 Bcfe for second quarter 2008 from 14.9 Bcfe in second quarter 2007.

DD&A for other assets consists primarily of depreciation of drilling rigs, midstream gathering and compression facilities and other equipment. DD&A for other assets for the three months ended June 30, 2008 was $15.8 million compared to $12.1 million in the same period in 2007. The increase from the 2007 period to the 2008 period was primarily attributable to higher carrying costs of the company’s rigs due to upgrades and retrofitting during 2007 and higher carrying costs of its midstream gathering and processing assets due to upgrades made throughout 2007 and the first half of 2008.

General and administrative expenses increased $13.3 million to $26.2 million for the three months ended June 30, 2008 from $12.9 million for the comparable period in 2007. The increase was principally attributable to a $12.4 million increase in corporate salaries and wages due to growth in the number of company corporate and support staff employees. As of June 30, 2008, SandRidge had 2,471 employees compared to 2,046 at June 30, 2007. General and administrative expenses include non-cash stock compensation expense of $4.1 million for the three months ended June 30, 2008 compared to $1.2 million for the same period in 2007. The increases in salaries and wages as well as stock compensation were partially offset by $4.3 million in capitalized general and administrative expenses for the three

months ended June 30, 2008. There were no general and administrative expenses capitalized during the three months ended June 30, 2007. In accordance with the full-cost method of accounting, the company capitalizes internal costs that can be directly identified with acquisitions, exploration and development activities and does not capitalize any costs related to production, general corporate overhead or similar activities.

For the three-month period ended June 30, 2008, the company recorded a loss of $159.8 million ($101.8 million unrealized loss and $58.0 million realized loss) on derivative contracts compared to a $39.2 million gain ($38.5 million unrealized gain and $0.7 million realized gain) for the same period in 2007. During 2007 and 2008, the company entered into natural gas and crude oil swaps and basis swaps. Given the long-term nature of the company’s investment in the WTO development program, the company believes it is prudent to enter into commodity swaps for a portion of its production in order to stabilize future cash inflows for planning purposes. Unrealized gains or losses on natural gas and crude oil derivative contracts represent the change in fair value of open derivative positions during the period. The unrealized losses recorded in second quarter 2008 were attributable to increases in natural gas and crude oil commodity prices from March 31, 2008 to June 30, 2008. Realized gains or losses represent the total change in the fair value, from inception to the date of settlement, of derivative contracts settled during the period.

Gain on sale of assets increased $7.1 million in second quarter 2008 compared to the same period in 2007 primarily due to the gain associated with the sale of company assets in Colorado in May 2008. The portion of the company’s net proceeds attributable to the gathering and compression systems and facilities sold exceeded the book basis of those assets resulting in a gain on sale of approximately $7.5 million. The sale of its acreage and working interests in wells was accounted for as an adjustment to the full cost pool, with no gain or loss recognized.

Other Income (Expense): Total net other expense decreased to $19.4 million in the three-month period ended June 30, 2008 from $21.0 million in the three-month period ended June 30, 2007. Interest income was $1.3 million for the three months ended June 30, 2008 compared to $2.1 million for the same period in 2007. This decrease generally was due to lower excess cash levels during second quarter 2008 compared to the same period in 2007. Interest expense (net of capitalized interest of $0.1 million) decreased to $22.2 million for the three months ended June 30, 2008, as a result of a $9.6 million unrealized gain recognized on the company’s interest rate swap, from $24.7 million (net of $0.5 million in capitalized interest) for the same period in 2007. Excluding the effects of the unrealized gain, second quarter 2008 interest expense increased to $31.9 million from $24.7 million during the same period of 2007 as a result of higher average long-term debt balances outstanding during second quarter 2008 compared to second quarter 2007. During the three months ended June 30, 2008, income from equity investments was $0.6 million compared to $1.1 million during the same period in 2007.

Income Tax Expense (Benefit): The company reported an income tax benefit of $10.8 million for the three months ended June 30, 2008, compared to an income tax expense of $19.6 million for the same period in 2007. The current period income tax benefit represents an effective income tax rate of 35%, which is relatively unchanged from the comparable period in 2007. Generally, for financial reporting purposes, federal income tax expenses are recorded as deferred income taxes until any available net operating loss carryforwards are utilized. The company treated 100% of the second quarter 2008 tax benefit as deferred.

First Six Months 2008 Results

Revenue: Total revenue increased 110% to $647.1 million for the six months ended June 30, 2008 from $308.1 million in the same period in 2007 primarily due to a $291.2 million increase in natural gas and crude oil sales. Lower drilling and services revenues for the six months ended June 30, 2008 partially offset an increase in midstream and marketing revenue.

Total natural gas and crude oil revenues increased to $497.6 million for the six months ended June 30, 2008 compared to $206.5 million for the same period in 2007, primarily as a result of an increase in natural gas and crude oil production volumes and prices received for the company’s production. Total natural gas production increased 83% to 40.9 Bcf in the first six months of 2008 compared to 22.3 Bcf in

the same period of 2007, while crude oil production increased 36% to 1,231 MBbls in 2008 from 906 MBbls in 2007. The average price received, excluding the impact of derivative contract settlements, for natural gas sales increased 32% in the six months ended June 30, 2008 to $9.11 per Mcf compared to $6.90 per Mcf in the same period in 2007. The average price received, excluding the impact of derivative contract settlements, for SandRidge’s crude oil production increased 75%, or $43.37 per barrel, to $101.55 per barrel during the first half of 2008 from $58.18 per barrel in the same period in 2007. Including the impact of derivative contract settlements, the effective price received for natural gas for the 2008 period was $8.11 per Mcf compared to $6.86 per Mcf in the same period in 2007. Including the effect of derivative contract settlements, the effective price received for crude oil during the first six months of 2008 was $93.74 per barrel. SandRidge’s derivative contracts had no impact on effective oil prices during the six months ended June 30, 2007.

Drilling and services revenue decreased 40% to $24.3 million for the six months ended June 30, 2008 compared to $40.2 million in the same period in 2007 due to the increase in the number of wells drilled for the company’s own account and its increased working interest ownership in those wells. The company records drilling revenues only on wells drilled for or on behalf of third parties. During the six months ended June 30, 2008 the company had an average 25 of its 28 total operational rigs drilling on its own behalf compared to an average 17 of its 26 total operational rigs drilling on its own behalf during the same period in 2007. Additionally, the average daily revenue per rig working for third parties declined to approximately $14,000 per rig per day worked during the six months ended June 30, 2008 compared to an average of approximately $24,500 per rig per day worked during the same period in 2007. During the six months ended June 30, 2007, two of the company’s rigs working for third parties were operating under turnkey contracts, which resulted in higher average revenues earned per day compared to revenues earned per day by rigs working under daywork contracts. None of the company’s rigs operated under turnkey contracts during the six months ended June 30, 2008.

Midstream and marketing revenue increased $63.8 million, or 122%, to $115.9 million in the six-month period ended June 30, 2008 compared to $52.1 million in the six-month period ended June 30, 2007 due to increased production volumes transported and marketed for third parties. Higher natural gas prices prevalent during the first six months of 2008 compared to the same period in 2007 also contributed to the increase.

Other revenue totaled $9.3 million for the six months ended June 30, 2008 as well as for the same period in 2007.

Operating Costs and Expenses: Total operating costs and expenses increased to $721.7 million for the six months ended June 30, 2008 compared to $229.5 million for the same period in 2007 due to $296.6 million in realized and unrealized losses on derivative contracts as well as increases in production-related costs, general and administrative expenses, and depreciation, depletion and amortization. These increases were partially offset by a decrease in expenses attributable to the company’s drilling and services business. Excluding the effects of gains and losses on derivative contracts, total operating costs for the six months ended June 30, 2008 and 2007 were $425.1 million and $245.5 million, respectively.

Production expenses increased $25.4 million primarily due to the increase in the number of wells in which the company owns a working interest. Production taxes increased $14.8 million, or 187%, to $22.7 million due to the increased production and prices received for that production during the six-month period ended June 30, 2008.

Drilling and services expenses decreased 49% to $12.2 million for the six months ended June 30, 2008 compared to $24.1 million for the same period in 2007 primarily due to the increase in the number and working interest ownership of the wells drilled for the company’s own account. Costs incurred relating to wells drilled by the company’s drilling and oil field services business for the company’s own account are capitalized as part of the full cost pool rather than recognized as expense.

Midstream and marketing expenses increased $58.4 million, or 125%, to $105.2 million due to larger third-party production volumes transported and marketed during the six months ended June 30, 2008 compared to the same period in 2007.

DD&A for natural gas and crude oil properties increased to $137.3 million for the six months ended June 30, 2008 from $70.7 million for the same period in 2007. DD&A per Mcfe increased $0.30 to $2.85 in 2008 from $2.55 in the comparable period in 2007. Production increased 74% to 48.3 Bcfe from 27.7 Bcfe in 2007.

DD&A for other assets increased to $33.7 million for the six months ended June 30, 2008 from $22.3 million for the comparable period of 2007 due to the higher average carrying costs of the company’s drilling rigs and gathering and compression facilities during the 2008 period compared to the 2007 period.

General and administrative expenses increased $21.8 million to $47.2 million for the six months ended June 30, 2008 from $25.4 million for the comparable period in 2007 due principally to a $21.2 million increase in corporate salaries and wages. General and administrative expenses include non-cash stock compensation expense of $7.3 million for the six months ended June 30, 2008 compared to $2.3 million for the same period in 2007. The increases in salaries and wages as well as stock compensation were partially offset by $7.5 million in capitalized general and administrative expenses for the six months ended June 30, 2008. There were no general and administrative expenses capitalized during the six months ended June 30, 2007.

As a result of continued increases in average natural gas and crude oil commodity prices from December 31, 2007 to June 30, 2008, the company recorded a loss of $296.6 million ($245.9 million unrealized loss and $50.7 million realized loss) on derivative contracts for the six months ended June 30, 2008 compared to a $16.0 million gain ($16.8 million unrealized gain and $0.8 million realized loss) for the comparable period in 2007.

Gain on sale of assets increased to $7.7 million in the first six months of 2008 compared to $0.7 million in the same period in 2007 primarily due to the gain associated with the sale of company assets in Colorado in May 2008.

Other Income (Expense): Total net other expense decreased to $43.7 million in the six-month period ended June 30, 2008 from $54.5 million in the same period in 2007. Interest income decreased to $2.1 million for the six months ended June 30, 2008 from $3.1 million for the same period in 2007. This decrease generally was due to lower excess cash levels during the six months ended June 30, 2008 compared to the same period in 2007. Interest expense (net of capitalized interest of $0.4 million) decreased to $47.4 million for the six months ended June 30, 2008, as a result of a $10.4 million unrealized gain recognized on the company’s interest rate swap, from $60.1 million (net of $0.9 million in capitalized interest) for the same period in 2007. Excluding the effects of the unrealized gain and the effects of the expensing, in March 2007, of approximately $12.5 million in unamortized debt issuance costs related to the company’s senior bridge loan, interest expense for the first six months of 2008 increased to $57.8 from $47.6 million during the same period in 2007 as a result of higher average long-term debt balances outstanding during the first six months of 2008 compared to the first six months of 2007. During the six months ended June 30, 2008, income from equity investments was $1.4 million compared to $2.2 million during the same period in 2007.

Income Tax Expense (Benefit): The company reported an income tax benefit of $41.4 million for the six months ended June 30, 2008, compared to an expense of $9.1 million for the same period in 2007. The current period income tax benefit represents an effective income tax rate of 35%, which is relatively unchanged from the comparable period in 2007. The company treated 100% of the tax benefit for the six months ended June 30, 2008 as deferred.

Non-GAAP Financial Measures

The company defines operating cash flow as net cash provided by operating activities before changes in operating assets and liabilities. It defines EBITDA as net (loss) income before income tax expense (benefit), interest expense, and depreciation, depletion and amortization. Adjusted EBITDA, which is a defined term in the company’s credit agreement, is EBITDA excluding interest income and various non-cash items (including income from equity investments, minority interest, stock-based compensation, unrealized (gain) loss on derivative contracts, and provision for doubtful accounts).

Operating cash flow and adjusted EBITDA are supplemental financial measures used by the company’s management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company also uses these measures because operating cash flow and adjusted EBITDA relate to the timing of cash receipts and disbursements that the company may not control and may not relate to the period in which the operating activities occurred. Further, operating cash flow and adjusted EBITDA allow the company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. These measures should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles (“GAAP”). Adjusted EBITDA should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, the company’s adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Management also uses the supplemental financial measure of adjusted net income available (loss applicable) to common stockholders, which excludes unrealized (losses) gains on derivative contracts from net income available (loss applicable) to common stockholders. Management uses this financial measure as an indicator of the company’s operational trends and performance relative to other oil and natural gas companies and believes it is more comparable to earnings estimates provided by securities analysts. Adjusted net income available (loss applicable) to common stockholders is not a measure of financial performance under GAAP and should not be considered a substitute for net income available (loss applicable) to common stockholders.

The tables below reconcile the most directly comparable GAAP financial measures to operating cash flow, EBITDA, adjusted EBITDA, and adjusted net income available (loss applicable) to common stockholders.

Reconciliation of Net Cash Provided by Operating Activities to Operating Cash Flow


	Three Months Ended June 30,					Six Months Ended June 30,
	2008		2007			2008			2007
	(in thousands)					(in thousands)
Net cash provided by operating activities	$	140,145	$	136,881		$	296,834		$	180,844
Add (deduct):
Change in operating assets and liabilities		4,991		(70,973	)		(8,387	)		(67,747	)

Operating cash flow	$	145,136	$	65,908		$	288,447		$	113,097

Reconciliation of Net (Loss) Income to EBITDA and Adjusted EBITDA


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Net (loss) income⁽¹⁾	$	(20,343	)	$	34,564		$	(76,968	)	$	15,071

Adjusted for:
Income tax (benefit) expense		(10,847	)		19,583			(41,385	)		9,082
Interest expense⁽²⁾		31,866			24,679			57,844			60,108
Depreciation, depletion and amortization — other		15,780			12,103			33,745			22,263
Depreciation, depletion and amortization — natural gas and crude oil		72,256			38,015			137,332			70,699

EBITDA		88,712			128,944			110,568			177,223

Income from equity investments		(556	)		(1,139	)		(1,415	)		(2,164	)
Minority interest		16			11			851			157
Interest income		(1,333	)		(2,138	)		(2,145	)		(3,127	)
Stock-based compensation		4,019			1,188			7,260			2,259
Unrealized losses (gains) on derivative contracts		92,122			(38,436	)		235,489			(16,774	)


Adjusted EBITDA	$	182,980		$	88,430		$	350,608		$	157,574


⁽¹⁾		Includes gain on sale of assets

⁽²⁾		Excludes unrealized (gain) loss of ($9.6) million and ($10.4) million on interest rate swap for the three and six month periods ended June 30, 2008, respectively.

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Net cash provided by operating activities	$	140,145		$	136,881		$	296,834		$	180,844

Changes in operating assets and liabilities		4,991			(70,973	)		(8,387	)		(67,747	)
Interest expense⁽¹⁾		31,866			24,679			57,844			60,108
Unrealized (losses) gains on derivative contracts		(92,122	)		38,436			(235,489	)		16,774
Gain on sale of assets		7,734			658			7,711			659
Other non-cash items		90,366			(41,251	)		232,095			(33,064	)


Adjusted EBITDA	$	182,980		$	88,430		$	350,608		$	157,574


⁽¹⁾		Excludes unrealized (gain) loss of ($9.6) million and ($10.4) million on interest rate swap for the three and six month periods ended June 30, 2008, respectively.

Reconciliation of Net Income Available (Loss Applicable) to Common Stockholders to Adjusted Net Income Available (Loss Applicable) to Common Stockholders


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Net income available (loss applicable) to common stockholders	$	(26,993	)	$	22,270		$	(93,200	)	$	(6,189	)

Unrealized losses (gains) on derivative contracts		92,122			(38,436	)		235,489			(16,774	)
Effect of income taxes		(32,037	)		13,901			(82,267	)		6,317


Adjusted net income available (loss applicable) to common stockholders	$	33,092		$	(2,265	)	$	60,022		$	(16,646	)


Per share — basic and diluted	$	0.21		$	(0.02	)	$	0.41		$	(0.17	)

Capital Expenditures

Second quarter 2008 capital expenditures were $523.2 million, bringing total capital expenditures for the first six months of 2008 to $934.3 million. During second quarter 2008, exploration and development expenditures were $458.7 million with $348.3 million allocated to drilling and production and $110.4 million allocated to leasehold and seismic data acquisitions. Drilling capital expenditures were concentrated as follows: $253.7 million related to properties in the WTO, $89.5 million to Non-WTO properties, and $5.1 million to the company’s tertiary recovery projects. Second quarter 2008 exploration and development expenditures include $4.3 million in capitalized general and administrative expense. Second quarter 2008 drilling expenditures increased from $166.3 million during the second quarter 2007 as the company continued to ramp up drilling activity in the WTO.

Capital expenditures related to the drilling and oil field services business were $17.9 million during second quarter 2008 compared to $42.7 million during the same period in 2007. In 2007 the company incurred higher levels of capital expenditures in its drilling and oil field services business during the build out of its rig fleet. Capitalized interest was also higher during the build out, decreasing to $0.1 million in second quarter 2008 compared to $0.5 million in second quarter 2007. The company ceased capitalizing interest when the last retrofitted rig was placed into service during second quarter 2008.

The company’s midstream business incurred capital expenditures of $38.2 million during second quarter 2008 compared to $13.6 million during the same period in 2007 as the company continued to build pipeline infrastructure and add compression in the WTO.

Capital expenditures related to other assets and businesses totaled $8.4 million during second quarter 2008 compared to other capital expenditures during second quarter 2007 of $6.2 million.

The table below summarizes the company’s capital expenditures for the three and six-month periods ended June 30, 2008 and 2007:


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
	(in thousands)				(in thousands)
Drilling and production
WTO	$	253,721	$	117,800	$	489,827	$	188,483
Non-WTO (excluding tertiary)		89,548		42,557		155,191		77,281
Tertiary		5,060		5,908		9,369		9,076

		348,329		166,265		654,387		274,840

Leasehold and seismic
WTO		88,550		76,283		116,590		82,532
Non-WTO (excluding tertiary)		21,800		4,365		42,244		16,434
Tertiary		4		1,668		84		1,748

		110,354		82,316		158,918		100,714

Total exploration and development		458,683		248,581		813,305		375,554


Drilling and oil field services		17,870		42,671		35,791		83,914
Midstream		38,203		13,587		69,429		23,130
Other — general		8,445		6,210		15,776		9,546


Total capital expenditures	$	523,201	$	311,049	$	934,301	$	492,144

Proved Reserves

The company’s estimated proved reserves as of June 30, 2008 were 1.918 Tcfe, representing a 13% increase from March 31, 2008 proved reserves of 1.699 Tcfe and a 27% increase from December 31, 2007 proved reserves of 1.516 Tcfe. Quarterly 2008 estimates of proved reserves were internally prepared and have not been reviewed by third-party engineers. Drilling finding costs were $1.37 per Mcfe and $1.43 per Mcfe for the three and six-month periods ended June 30, 2008, respectively. The all-in finding costs, which include drilling, acquisitions, land, and seismic costs, were $1.80 per Mcfe and $1.77 per Mcfe for the three and six-month periods ended June 30, 2008, respectively. Proved developed reserves constituted 46% of total reserves as of June 30, 2008 compared to 43% at March 31, 2008 and 44% at December 31, 2007. The June 30, 2008 estimated future net cash flows from proved reserves, discounted at an annual rate of 10% before income taxes (“PV-10”) were $10.61 billion, an increase of 93% from March 31, 2008 PV-10 of $5.50 billion and 199% from December 31, 2007 PV-10 of $3.55 billion. On an after-tax basis (SFAS 69 standardized measure), such year-end future net cash flows were $2.72 billion.

The company calculates the standardized measure of future net cash flows in accordance with SFAS 69 only at year end because applicable income tax information on properties, including recently acquired natural gas and oil interests, is not readily available at other times during the year. As a result, the company is not able to reconcile the interim period-end values to the standardized measure at such dates. The only difference between the two measures is that PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects.

Increases in price per unit of future production accounted for $3.93 billion, or 77%, of the total increase in PV-10 from March 31, 2008 to June 30, 2008 and $5.42 billion, or 77%, of the total increase in PV-10 from December 31, 2007 to June 30, 2008. The calculated weighted average per unit prices for the company’s proved reserves and future net revenues were $12.98 per Mcf for natural gas and $130.68 per barrel for crude oil at June 30, 2008 compared to $8.51 per Mcf for natural gas and $96.46 per barrel for crude oil at March 31, 2008 and $6.46 per Mcf for natural gas and $87.47 per barrel for crude oil at December 31, 2007.

Analysis of Changes in Proved Reserves


	Crude Oil			Natural Gas			Combined
	(MBbls)			(Bcf)			(Bcfe)
As of December 31, 2007		36,527			1,297			1,516

Revisions of previous estimates		2,728			125			141
Acquisitions of new reserves		3			1			2
Sales of reserves in place		—			—			—
Extensions and discoveries		412			61			63
Production		(611	)		(19	)		(23	)


As of March 31, 2008		39,059			1,465			1,699

Revisions of previous estimates		7,141			105			148
Acquisitions of new reserves		—			—			—
Sales of reserves in place		(66	)		(10	)		(10	)
Extensions and discoveries		234			106			107
Production		(620	)		(22	)		(26	)


As of June 30, 2008		45,748			1,644			1,918

Reserve Replacement Economics


										3 - Year			Quarter Ended			Six Months Ended
	2005			2006			2007			Average			June 30, 2008			June 30, 2008
							(in millions except as noted)
Proved reserves (Bcfe)		300.0			1,001.8			1,516.2						1,917.7			1,917.7
% Proved reserve growth		102	%		234	%		51	%					13	%		27	%
% Proved developed		25	%		32	%		44	%					46	%		46	%
Annual Production (Bcfe)		7.3			15.3			64.2			28.9			n/m			n/m
% Production growth		2	%		110	%		320	%		41.4	(1)		n/m			n/m
Proved reserve life (years)		41.0			19.0	(1)		23.6						n/m			n/m
PDP reserve life (years)		10.2			7.1	(1)		10.4						n/m			n/m

Excluding acquisitions
F&D Reserve additions (Bcfe)		69.7			120.4			503.2			231.1			254.5			458.7
F&D Costs incurred	$	62.9		$	133.8		$	808.7		$	335.1		$	348.3		$	654.4
F&D Costs per Mcfe	$	0.90		$	1.11		$	1.61		$	1.45		$	1.37		$	1.43
Drillbit reserve replacement		955	%		787	%		784	%		799	%		998	%		950	%

Including acquisitions
Total reserve additions (Bcfe)		158.8			717.1			578.7			484.9			254.6			460.1
Total costs incurred	$	98.5		$	1,713.6		$	1,150.6		$	987.6		$	458.7		$	813.3
Reserve replacement cost per Mcfe	$	0.62		$	2.39		$	1.99		$	2.04		$	1.80		$	1.77
Proved reserve replacement		2,175	%		1,361%	(1)		901	%		1,171%	(1)		998	%		953	%


(1)		Based upon pro forma 2006 production of 52.7 Bcfe

Derivative Contracts

SandRidge currently has natural gas price and basis swaps and crude oil swaps and collars in place through December 2011 (see tables below, which set forth positions for 2008 and 2009 as of August 5, 2008). The company has no derivative contracts for 2010, and has 5.48 Bcf of natural gas basis swaps in 2011 at a price of $0.47 per Mcf. Current natural gas and crude oil derivative contracts excluding basis swaps account for 77% of anticipated production for 2008 and 17% of anticipated production for 2009.


					Year										Year
	Quarter Ending				Ending		Quarter Ending								Ending
	9/30/2008		12/31/2008		12/31/2008		3/31/2009		6/30/2009		9/30/2009		12/31/2009		12/31/2009
Natural Gas Swaps:
Volume (Bcf)⁽¹⁾		19.94		17.48		70.77		10.80		5.46		3.07		2.76		22.09
Swap	$	8.60	$	8.67	$	8.40	$	10.17	$	9.39	$	9.95	$	10.42	$	9.98

Natural Gas Basis Swaps:
Volume (Bcf)⁽¹⁾		15.64		14.72		55.54		3.60		3.64		3.68		3.68		14.60
Swap	$	0.57	$	0.65	$	0.60	$	0.60	$	0.60	$	0.60	$	0.60	$	0.60

Crude Oil Hedges:
Swap Volume (MMBbls)		0.23		0.23		0.92		0.05		0.05		0.05		0.05		0.18
Swap	$	94.33	$	93.17	$	94.55	$	126.38	$	126.71	$	126.61	$	126.51	$	126.55
Collar Volume (MMBbls)		0.03		0.03		0.10		0.00		0.00		0.00		0.00		0.00
Collar: High	$	82.60	$	82.60	$	82.93		n/m		n/m		n/m		n/m		n/m
Collar: Low	$	50.00	$	50.00	$	50.00		n/m		n/m		n/m		n/m		n/m


(1)		Assumes ratio of 1:1 for Mcf to MMBtu

As compared to its derivative positions on May 8, 2008, the company has entered into the following additional natural gas and crude oil swaps (also included in the tables above of derivative contracts as of August 5, 2008):


					Year										Year
	Quarter Ending				Ending		Quarter Ending								Ending
	9/30/2008		12/31/2008		12/31/2008		3/31/2009		6/30/2009		9/30/2009		12/31/2009		12/31/2009
Natural Gas Swaps:
Volume (Bcf)⁽¹⁾		1.84		0.00		1.84		0.90		0.91		2.76		2.76		7.33
Swap	$	12.28		n/m	$	12.28	$	11.44	$	10.01	$	9.98	$	10.42	$	10.33

Natural Gas Basis Swaps:
Volume (Bcf)⁽¹⁾		0.00		0.00		0.00		0.90		0.91		0.92		0.92		3.65
Swap		n/m		n/m		n/m	$	0.93	$	0.93	$	0.93	$	0.93	$	0.93

Crude Oil Hedges:
Swap Volume (MMBbls)		0.00		0.00		0.00		0.05		0.05		0.05		0.05		0.18
Swap		n/m		n/m		n/m	$	126.38	$	126.71	$	126.61	$	126.51	$	126.55
Collar Volume (MMBbls)		0.00		0.00		0.00		0.00		0.00		0.00		0.00		0.00
Collar: High		n/m		n/m		n/m		n/m		n/m		n/m		n/m		n/m
Collar: Low		n/m		n/m		n/m		n/m		n/m		n/m		n/m		n/m

(1) Assumes ratio of 1:1 for Mcf to MMBtu

Balance Sheet

The company’s total debt (short-term and long-term) increased $742.4 million during the first six months of 2008 primarily as a result of the issuance of $750.0 million of 8.0% Senior Notes Due 2018 in May 2008. The company used $478.0 million of the $735.0 million of net proceeds from the offering to repay borrowings under the company’s senior credit facility. Additionally, during the six months ended June 30, 2008, the company made principal payments on its rig loan and mortgage totaling $7.0 million and $0.4 million, respectively. At June 30, 2008 the company had classified $15.9 million of its long-term debt as current. This total included $0.9 million related to the company’s mortgage and $15.0 million related to its rig loan. As of June 30, 2008, total debt was $1.810 billion compared to $1.068 billion at year-end 2007.

In May 2008, the company converted the remaining outstanding 1,844,464 shares of its redeemable convertible preferred stock into 18,810,260 shares of its common stock. Previously, holders of 339,823 shares of the company’s redeemable convertible preferred stock had voluntarily converted those shares into 3,465,593 shares of common stock during first quarter 2008.

The company’s capital structure at June 30, 2008 and December 31, 2007 is presented below:


	December 31,			June 30,
	2007			2008
	(in thousands)
Cash and cash equivalents	$	63,135		$	275,888


Current maturities of long-term debt		15,350			15,874
Long-term debt (net of current maturities):
Senior credit facility		—			—
Notes payable — Drilling rig fleet and oil field services equipment		33,416			25,768
Mortgage		18,829			18,392
Notes payable — Other equipment and vehicles		54			—
Term loans and Senior Notes:
Senior Floating Rate Term Loan		350,000			—
8.625% Senior Term Loan		650,000
Senior Floating Rate Notes due 2014		—			350,000
8.625% Senior Notes due 2015		—			650,000
8.0% Senior Notes due 2018		—			750,000

Total debt		1,067,649			1,810,034

Minority interest		4,672			1,464

Redeemable convertible preferred stock		450,715			—

Stockholders’ equity:
Preferred stock		—			—
Common stock		140			163
Additional paid-in capital		1,686,113			2,154,267
Treasury stock, at cost		(18,578	)		(18,043	)
Retained earnings		99,216			6,016

Total stockholders’ equity		1,766,891			2,142,403


Total capitalization	$	3,289,927		$	3,953,901

2008 and 2009 Operational Guidance


	Year Ending						Year Ending
	December 31, 2008						December 31, 2009
	Previous			Updated			Current
	Projection			Projection			Projection
	as of May 8, 2008			as of August 7, 2008			as of August 7, 2008
Production
Natural Gas (Bcf)		86.6			85.1			120.0
Crude Oil (MMBbls)		2.2			2.5			2.5

Total (Bcfe)		100.0			100.0			135.0

Differentials
Natural Gas	$	0.70		$	0.90		$	0.90
Crude Oil		7.25			10.00			10.00

Costs per Mcfe
Lifting	$	1.58- $1.73		$	1.56- $1.72		$	1.56- $1.72
Production Taxes		0.37 - 0.40			0.44 - 0.49			0.37 - 0.40
DD&A — oil & gas		2.74 - 3.01			2.85 - 3.13			2.71 - 2.98
DD&A — other		0.80 - 0.88			0.76 - 0.84			0.79 - 0.87

Total DD&A	$	3.54- $3.89		$	3.61- $3.97		$	3.50- $3.85
G&A — cash		0.82 - 0.90			0.82 - 0.91			0.68 - 0.75
G&A — stock		0.25 - 0.28			0.20 - 0.22			0.34 - 0.37

Total G&A	$	1.07- $1.18		$	1.02- $1.13		$	1.02- $1.12
Interest Expense	$	1.18- $1.30		$	1.23- $1.35		$	1.33- $1.46

Corporate Tax Rate		36	%		36	%		36	%
Deferral Rate		95	%		95	%		95	%

Shares Outstanding at End of Period (in millions)
Common Stock		165.8			165.8			179.1
Preferred Stock (converted)		0.0			0.0			0.0

Fully Diluted		165.8			165.8			179.1

Capital Expenditures ($ in millions)
Drilling and Production	$	996		$	1,472		$	1,600
Leasehold and Seismic		242			305			125

Total Exploration and Development	$	1,238		$	1,777		$	1,725
Drilling and Oil Field Services		67			64			75
Midstream and Other		195			159			200

Total Capital Expenditures	$	1,500		$	2,000		$	2,000

The updated 2008 and initial 2009 operational guidance presented above and discussed below have not been adjusted to include the effects of a potential sale of the company’s East Texas and North Louisiana assets and assume that a 2009 cash flow shortfall will be funded with balanced issuances of equity and debt.

2008 Guidance Update: The company is updating the guidance provided on May 8, 2008 as shown above. Production guidance remains at 100.0 Bcfe despite shut-in volumes resulting from the Grey Ranch plant fire and well work in the Gulf Coast. Projected differentials have been increased to reflect current market conditions relative to the first half of fiscal year 2008. The company’s capital expenditures projection has increased to $2.0 billion from $1.5 billion, reflecting plans for increased drilling throughout the remainder of 2008.

2009 Initial Operational Guidance: Production guidance for fiscal year 2009 reflects an increase of 35% over the 2008 projection as the company expects to see continued results from its drilling program.

Conference Call Information

The company will host a conference call to discuss these results on Friday, August 8, 2008 at 9:00 am EDT. The telephone number to access the conference call from within the U.S. is 866-356-4279 and from outside the U.S. is 617-597-5394. The passcode for the call is 28604095. An audio replay of the call will be available at 11:00 am CDT on August 8, 2008 until 11:59 pm CDT on August 22, 2008. The number to access the conference call replay from within the U.S. is 888-286-8010 and from outside the U.S. is 617-801-6888. The passcode for the replay is 65976231.

A live audio webcast of the conference call will also be available via SandRidge’s website, www.sandridgeenergy.com, under Investor Relations/Events. A brief slide presentation to be viewed in conjunction with this conference call is currently available at the same location on the website. The webcast will be archived for replay on the company’s website for 30 days.

Future 2008 Earnings Releases, Conference Calls and 2009 Investor/Analyst Conference Information

Third Quarter Earnings and Conference Call:

November 6, 2008 (Thursday) — Earnings press release and filing of 10-Q after market close
November 7, 2008 (Friday) — Earnings conference call at 9:00 am EST

Fourth Quarter and Year End 2008 Earnings and Conference Call:

February 26, 2009 (Thursday) — Earnings press release and filing of 10-K after market close
February 27, 2009 (Friday) — Earnings conference call at 9:00 am EST

2009 Investor/Analyst Conference:

March 3, 2009 (Tuesday) — New York, NY at the Grand Hyatt, 109 East 42^nd Street at 8:00 am EST

SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands, except per share amounts)
Revenues:
Natural gas and crude oil	$	292,134		$	116,274		$	497,621		$	206,450
Drilling and services		11,957			12,349			24,291			40,244
Midstream and marketing		69,488			25,914			115,897			52,101
Other		4,471			4,526			9,327			9,332

Total revenues		378,050			159,063			647,136			308,127

Expenses:
Production		40,254			27,044			74,442			49,018
Production taxes		13,519			4,993			22,739			7,926
Drilling and services		5,066			5,349			12,235			24,126
Marketing and midstream		64,733			23,327			105,151			46,747
Depreciation, depletion and amortization — natural gas and crude oil		72,256			38,015			137,332			70,699
Depreciation, depletion and amortization — other		15,780			12,103			33,745			22,263
General and administrative		26,203			12,892			47,197			25,360
Loss (gain) on derivative contracts		159,768			(39,162	)		296,612			(15,981	)
Gain on sale of assets		(7,734	)		(658	)		(7,711	)		(659	)

Total expenses		389,845			83,903			721,742			229,499

(Loss) income from operations		(11,795	)		75,160			(74,606	)		78,628


Other income (expense):
Interest income		1,333			2,138			2,145			3,127
Interest expense		(22,223	)		(24,679	)		(47,395	)		(60,108	)
Minority interest		(16	)		(11	)		(851	)		(157	)
Income from equity investments		556			1,139			1,415			2,164
Other income, net		955			400			939			499

Total other (expense) income		(19,395	)		(21,013	)		(43,747	)		(54,475	)

(Loss) income before income tax (benefit) expense		(31,190	)		54,147			(118,353	)		24,153
Income tax (benefit) expense		(10,847	)		19,583			(41,385	)		9,082

Net (loss) income		(20,343	)		34,564			(76,968	)		15,071
Preferred stock dividends and accretion		6,650			12,294			16,232			21,260

(Loss applicable) income available to common stockholders	$	(26,993	)	$	22,270		$	(93,200	)	$	(6,189	)


Basic and diluted (loss) income per share (applicable) available to common stockholders	$	(0.17	)	$	0.21		$	(0.63	)	$	(0.06	)

Weighted average number of common shares outstanding:
Basic		155,204			107,524			148,124			100,025

Diluted		155,204			108,602			148,124			100,025

SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets


	June 30,			December 31,
	2008			2007
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	275,888		$	63,135
Accounts receivable, net
Trade		143,974			94,741
Related parties		20,893			20,018
Derivative contracts		1,534			21,958
Inventories		6,476			3,993
Deferred income taxes		1,430			1,820
Costs incurred in excess of billings		39,809			—
Other current assets		21,696			20,787

Total current assets		511,700			226,452

Natural gas and crude oil properties, using full cost method of accounting
Proved		3,519,253			2,848,531
Unproved		259,610			259,610
Less: accumulated depreciation and depletion		(363,879	)		(230,974	)

		3,414,984			2,877,167


Other property, plant and equipment, net		540,737			460,243
Derivative contracts		11,063			270
Investments		9,371			7,956
Restricted deposits		32,684			31,660
Other assets		45,271			26,818

Total assets	$	4,565,810		$	3,630,566


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current maturity of long-term debt	$	15,874		$	15,350
Accounts payable and accrued expenses:
Trade		295,751			215,497
Related parties		3,561			395
Asset retirement obligation		1,524			864
Derivative contracts		225,858			—

Total current liabilities		542,568			232,106

Long-term debt		1,794,160			1,052,299
Other long-term obligations		16,817			16,817
Asset retirement obligation		61,776			57,716
Deferred income taxes		6,622			49,350

Total liabilities		2,421,943			1,408,288


Commitments and contingencies
Minority interest		1,464			4,672
Redeemable convertible preferred stock, $0.001 par value, 2,625 shares authorized; 0 and 2,184 shares issued and outstanding at June 30, 2008 and December 31, 2007		—			450,715

Stockholders’ equity:
Preferred stock, $0.001 par value; 47,375 shares authorized; no shares issued and outstanding in 2008 and 2007		—			—
Common stock, $0.001 par value; 400,000 shares authorized; 166,315 issued and 164,991 outstanding at June 30, 2008 and 141,847 issued and 140,391 outstanding at December 31, 2007		163			140
Additional paid-in capital		2,154,267			1,686,113
Treasury stock, at cost		(18,043	)		(18,578	)
Retained earnings		6,016			99,216

Total stockholders’ equity		2,142,403			1,766,891

Total liability and stockholders’ equity	$	4,565,810		$	3,630,566

SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows


	Six Months Ended June 30,
	2008			2007
	(Unaudited)
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(76,968	)	$	15,071
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		171,077			92,962
Debt issuance cost amortization		2,445			13,822
Deferred income taxes		(42,338	)		9,082
Unrealized loss (gain) on derivative contracts		235,489			(16,774	)
Gain on sale of assets		(7,711	)		(659	)
Interest income — restricted deposits		(243	)		(660	)
Income from equity investments		(1,415	)		(2,163	)
Stock-based compensation		7,260			2,259
Minority interest		851			157
Changes in operating assets and liabilities		8,387			67,747

Net cash provided by operating activities		296,834			180,844


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures from property, plant and equipment		(934,301	)		(492,144	)
Proceeds from sale of assets		153,191			2,807
Loans to unconsolidated investees		(4,000	)		—
Fundings of restricted deposits		(781	)		(3,973	)

Net cash used in investing activities		(785,891	)		(493,310	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,408,000			1,152,772
Repayments of borrowings		(665,615	)		(1,154,443	)
Dividends paid — preferred		(17,552	)		(15,409	)
Minority interest (distributions) contributions		(4,059	)		522
Proceeds from issuance of common stock		—			319,966
Purchase of treasury stock		(1,908	)		(1,572	)
Debt issuance costs		(17,056	)		(26,119	)

Net cash provided by financing activities		701,810			275,717


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		212,753			(36,749	)
CASH AND CASH EQUIVALENTS, beginning of year		63,135			38,948

CASH AND CASH EQUIVALENTS, end of year	$	275,888		$	2,199


Supplemental Disclosure of Noncash Investing and Financing Activities:
Insurance premiums financed	$	—		$	1,496
Accretion on redeemable convertible preferred stock		7,636			705
Redeemable convertible preferred stock dividends, net of dividends paid		—			8,956

For further information, please contact:

Dirk M. Van Doren
Chief Financial Officer
SandRidge Energy, Inc.
1601 N.W. Expressway, Suite 1600
Oklahoma City, OK 73118
(405) 753-5520

This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include projections and estimates of future natural gas and oil production, pricing differentials, operating costs and capital spending, descriptions of our development plans and provide internal estimates of proved reserves and future net cash flows. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of natural gas and oil prices, our success in discovering, estimating, developing and replacing natural gas and oil reserves, the availability and terms of capital, developments related to the marketing of our East Texas and North Louisiana properties, the amount and timing of future development costs and other factors, many of which are beyond our control. We refer you to the discussion of risks in Item 1A - Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2007 filed with the Securities and Exchange Commission on March 7, 2008. All of the forward-looking statements made in this press release are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to update or revise any forward-looking statements.

The company’s management uses proved reserve replacement as an indicator of its ability to replenish annual production volumes and grow its reserves. The company’s management believes that reserve replacement is relevant and useful information that is commonly used by analysts, investors and other interested parties in the oil and gas industry as a means of evaluating the operational performance and prospects of entities engaged in the production and sale of depleting natural resources. It should be noted that proved reserve replacement is a statistical indicator that has limitations. As an annual measure, proved reserve replacement is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since proved reserve replacement does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. This financial measure does not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop.

Cautionary Note to Investors — The United States SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in the press release, such as “probable reserves” and “possible reserves,” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the disclosures in our Forms 10-K, File No. 001-33784, available from us at 1601 N.W. Expressway, Suite 1600, Oklahoma City, Oklahoma 73118 or www.sandridgeenergy.com. You can also obtain these forms from the SEC by calling 1-800-732-0330.

SandRidge Energy, Inc. is a natural gas and crude oil company headquartered in Oklahoma City, Oklahoma with its principal focus on exploration and production. SandRidge also owns and operates gas gathering and processing facilities and CO₂treating and transportation facilities, and has marketing and tertiary oil recovery operations. In addition, SandRidge owns and operates drilling rigs and a related oil field services business operating under the Lariat Services, Inc. brand name. SandRidge focuses its exploration and production activities in West Texas, the Cotton Valley Trend in East Texas, the Gulf Coast, the Mid-Continent, and the Gulf of Mexico. SandRidge’s Internet address is www.sandridgeenergy.com.