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Article by DailyStocks_admin    (04-03-12 12:32 AM)

Description

Sandridge Enrgy. Director DANIEL JORDAN bought 50000 shares on 3-28-2012 at $ 7.85

BUSINESS OVERVIEW

GENERAL

SandRidge Energy, Inc. (including its consolidated subsidiaries and variable interest entities of which it is the primary beneficiary, the “Company” or “SandRidge”) is an independent oil and natural gas company headquartered in Oklahoma City, Oklahoma, concentrating on development and production activities related to the exploitation of its significant holdings in the Mid-Continent area of Oklahoma and Kansas and in west Texas. The Company’s primary focus in the Mid-Continent area is the Mississippian formation, a shallow hydrocarbon system in northern Oklahoma and Kansas, where it had approximately 1,329,000 net acres under lease at December 31, 2011. The Company’s primary area of focus in west Texas is the Permian Basin, where it had approximately 225,000 net acres under lease at December 31, 2011. The Company’s oil properties in the Permian Basin include properties acquired from Forest Oil Corporation and one of its subsidiaries (collectively, “Forest”) in December 2009 (the “Forest Acquisition”) and properties owned by Arena Resources, Inc. (“Arena”), which was acquired by the Company in July 2010 (the “Arena Acquisition”). The Company also owns and operates other interests in the Mid-Continent, West Texas Overthrust (the “WTO”), Gulf Coast and Gulf of Mexico.

As of December 31, 2011, the Company’s total estimated proved reserves were 470.6 MMBoe, of which approximately 52% were oil and approximately 49% were proved developed. As of December 31, 2011, the Company had 5,043 gross (4,266.9 net) producing wells, substantially all of which it operates, and approximately 2,695,000 gross (2,047,000 net) total acres under lease. As of December 31, 2011, the Company had 21 rigs drilling in the Mid-Continent and 15 rigs drilling in the Permian Basin.

The Company also operates businesses that are complementary to its primary development and production activities, including gas gathering and processing facilities, an oil and natural gas marketing business and an oil field services business, including its wholly owned drilling rig business, Lariat Services, Inc. (“Lariat”). As of December 31, 2011, the Company’s drilling rig fleet consisted of 30 operational rigs. The Company also captures and transports carbon dioxide (“CO 2” ) to the Permian Basin for use in tertiary recovery projects. “SandRidge CO 2 ” refers to the Company’s wholly owned subsidiary SandRidge CO 2 , LLC. These complementary businesses provide the Company with operational flexibility and an advantageous cost structure by reducing the Company’s dependence on third parties for these services.

The Company’s principal executive offices are located at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102 and the Company’s telephone number is (405) 429-5500. SandRidge makes available free of charge on its website at http:// www.sandridgeenergy.com its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the Securities and Exchange Commission (“SEC”). Any materials that the Company has filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549 or accessed via the SEC’s website address at http://www.sec.gov.

This report includes terms commonly used in the oil and natural gas industry, which are defined in the “Glossary of Oil and Natural Gas Terms” beginning on page 28.

BUSINESS STRATEGY

The Company’s primary objectives are to achieve long-term growth and maximize stockholder value over multiple business cycles by pursuing the following strategies:


•

Concentrate in Core Operating Areas. The Company’s primary areas of operation are (1) the Mid-Continent area of Oklahoma and Kansas and (2) west Texas. Concentrating the Company’s drilling and producing activities in these core areas allows the Company to further build and utilize its technical expertise in order to interpret specific geological and operational trends. By concentrating in these core areas, the Company is able to (i) achieve economies of scale and breadth of operations, both of which help to control costs, and (ii) opportunistically grow its holdings and operations in these areas in order to achieve production and reserve growth.


•

Focus on Conventional Reservoirs. The Company focuses its development efforts primarily in areas with conventional, shallow, low-cost, permeable carbonate reservoirs with decades of production history. The nature of these reservoirs allows the Company to execute low-risk, repeatable drilling programs with predictable production profiles and a higher certainty of economic returns. Further, due to these low pressure and shallow characteristics, the Company is able to mitigate rising service costs.


•

Pursue Opportunistic Acquisitions. The Company occasionally reviews acquisition targets to complement its existing asset base. Accordingly, the Company selectively identifies such targets based on several factors including relative value, oil content, location and, when appropriate, seeks to acquire them at a discount to other opportunities.


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Maintain Flexibility. The Company has multi-year inventories of both oil and natural gas drilling locations within its core operating areas. Additionally, the Company maintains its own fleet of drilling rigs through Lariat. Maintaining inventories of both oil and natural gas drilling locations as well as its own drilling rigs allows the Company to efficiently direct capital toward projects with the most attractive returns.


•

Mitigate Commodity Price Risk. The Company enters into derivative contracts in order to mitigate commodity price volatility inherent in the oil and natural gas industry. By increasing the predictability of cash inflows for a portion of its future production, the Company is better able to ensure funding for its longer term development plans and rates of return on its capital projects.


•

Monetize Assets . The Company periodically evaluates its properties to identify opportunities to monetize assets in order to fund or accelerate development within its areas of focus. Proceeds realized from such transactions may be used to pay down amounts outstanding under the Company’s senior secured revolving credit facility (the “senior credit facility”), to fund its drilling program or for general corporate purposes.

2011 DEVELOPMENTS

Divestitures

Sale of Wolfberry Assets . In July 2011, the Company sold its Wolfberry assets in the Permian Basin for $151.6 million, net of fees and post-closing adjustments. The divested properties included approximately 18,000 net acres with production at the time of sale of approximately 1,600 Boe/d.

Sale of New Mexico Assets . In August 2011, the Company sold certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for $199.0 million, net of fees and post-closing adjustments. The divested properties included approximately 23,000 net acres with production at the time of sale of approximately 1,500 Boe/d.

Sale of Working Interest in Mississippian Properties. In September 2011, the Company sold to Atinum MidCon I, LLC (“Atinum”) a 13.2% non-operated working interest, equal to approximately 113,000 net acres, in the Mississippian formation in northern Oklahoma and southern Kansas for approximately $287.0 million, subject to post-closing adjustments. Atinum will fund a drilling carry of 13.2% of SandRidge’s share of drilling and completion costs for wells drilled within an area of mutual interest up to $250.0 million, which is expected to occur over a three-year period.

Sale of East Texas Properties. In November 2011, the Company sold its east Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $231.0 million, subject to post-closing adjustments. The divested properties included over 23,000 net acres with production at the time of sale of approximately 4,100 Boe/d.

Royalty Trust Offerings

SandRidge Mississippian Trust I. In April 2011, SandRidge Mississippian Trust I (the “Mississippian Trust I”) completed its initial public offering of 17,250,000 common units representing approximately 61.6% of the beneficial interest in the Mississippian Trust I. Net proceeds to the Mississippian Trust I, after certain offering expenses, were $336.9 million. Concurrent with the closing of the offering, the Company conveyed certain royalty interests to the Mississippian Trust I in exchange for the net proceeds of the offering and 10,750,000 units, representing approximately 38.4% of the beneficial interest, in the Mississippian Trust I.

The Company and one of its wholly owned subsidiaries entered into a development agreement with the Mississippian Trust I that obligates the Company to drill, or cause to be drilled, a specified number of wells within an area of mutual interest, which are also subject to the royalty interest granted to the Mississippian Trust I, within a specified period. One of the Company’s wholly owned subsidiaries also granted a lien to the Mississippian Trust I on the Company’s interests in the properties where the development wells will be drilled in order to secure the estimated amount of the drilling costs for the wells.

The Company has determined that the Mississippian Trust I is a variable interest entity (“VIE”) and the Company is its primary beneficiary. As such, the Company began consolidating the activities of the Mississippian Trust I into its results of operations in April 2011. See Note 3 to the Company’s consolidated financial statements included in Item 8 of this report for further discussion regarding the Company’s consolidation of the Mississippian Trust I.

SandRidge Permian Trust. In August 2011, SandRidge Permian Trust (the “Permian Trust”) completed its initial public offering of 34,500,000 common units representing approximately 65.7% of the beneficial interest in the Permian Trust. Net proceeds to the Permian Trust, after certain offering expenses, were $580.6 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Permian Trust in exchange for the net proceeds of the offering and 18,000,000 units, representing approximately 34.3% of the beneficial interest in the Permian Trust.

The Company and one of its wholly owned subsidiaries entered into a development agreement with the Permian Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells within an area of mutual interest, which are also subject to the royalty interest granted to the Permian Trust, within a specified period. One of the Company’s wholly owned subsidiaries also granted a lien to the Permian Trust on the Company’s interests in the properties where the development wells will be drilled in order to secure the estimated amount of the drilling costs for the wells.

The Company has determined that the Permian Trust is a VIE and the Company is its primary beneficiary. As such, the Company began consolidating the activities of the Permian Trust into its results of operations in August 2011. See Note 3 to the Company’s consolidated financial statements included in Item 8 of this report for further discussion regarding the Company’s consolidation of the Permian Trust.

Debt Transactions

Issuance of 7.5% Senior Notes. In March 2011, the Company issued $900.0 million of unsecured 7.5% Senior Notes due 2021 (the “7.5% Senior Notes”) pursuant to Rule 144A and Regulation S under the Securities Act. Net proceeds from the offering were used to fund the tender offer for and the redemption of the 8.625% Senior Notes due 2015 (the “8.625% Senior Notes”), discussed below. As a result of this issuance, the Company’s borrowing base under its senior credit facility was reduced from $850.0 million to $790.0 million.

Repurchase and Redemption of 8.625% Senior Notes. In March 2011, the Company purchased approximately 94.5%, or $614.2 million, of the 8.625% Senior Notes, originally issued in an aggregate principal amount of $650.0 million, through a cash tender offer. In April 2011, the Company redeemed the remaining outstanding $35.8 million aggregate principal amount of the 8.625% Senior Notes.

2012 DEVELOPMENTS

Sale of Working Interest in Mississippian Properties. In January 2012, SandRidge sold to Repsol E&P USA Inc. (“Repsol”) an approximate 25% non-operated working interest, equal to approximately 250,000 net acres, in the Mississippian formation in western Kansas, and an approximate 16% non-operated working interest, equal to approximately 114,000 net acres and a proportionate share of existing salt water disposal facilities in the Mississippian formation in northern Oklahoma and southern Kansas for approximately $272.5 million. In addition, Repsol will pay for its working interest share of development costs and will fund a portion of SandRidge’s development costs equal to 200% of Repsol’s working interest for wells within an area of mutual interest up to $750.0 million, which is expected to occur over a five-year period.

Proposed Royalty Trust Offering. On January 5, 2012, the Company and SandRidge Mississippian Trust II (the “Mississippian Trust II”), a newly formed Delaware statutory trust, filed a joint registration statement with the SEC for the proposed public offering of common units representing beneficial interests in the Mississippian Trust II. In connection with the offering, the Company intends to convey certain royalty interests to the Mississippian Trust II in exchange for the net proceeds of the offering and units, representing a beneficial interest in the Mississippian Trust II. The royalty interests to be conveyed to the Mississippian Trust II are in certain existing wells and wells to be drilled on certain oil and natural gas properties leased by the Company in the Mississippian formation in northern Oklahoma and Kansas. There can be no assurance that the Company will complete this transaction, as it is subject to market conditions and other uncertainties, as well as completion of the SEC review process. If the transaction is completed, the Company intends to use the net proceeds from the offering for general corporate purposes, including to fund its 2012 capital expenditure program.

Dynamic Acquisition. On February 1, 2012, the Company entered into an agreement to acquire Dynamic, an oil and natural gas exploration, development and production company with operations in the Gulf of Mexico for approximately $1.3 billion, comprised of approximately $680.0 million in cash and approximately 74 million shares of the Company’s common stock. The acquisition, which is expected to close in the second quarter of 2012, is subject to customary closing conditions, including compliance with the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act. The Company has secured $725.0 million in committed financing for the acquisition that it may use to fund the cash portion of the acquisition.

Sale of Trust Units. On February 21, 2012, the Company sold approximately 1.6 million of its Mississippian Trust I common units in a transaction exempt from registration under Rule 144 under the Securities Act for proceeds of $52.3 million.

BUSINESS SEGMENTS AND PRIMARY OPERATIONS

The Company operates in three business segments: exploration and production, drilling and oil field services and midstream gas services. Financial information regarding each segment is provided in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The information below includes the activities of the Mississippian Trust I and the Permian Trust, including amounts attributable to noncontrolling interest, all of which are included in the exploration and production segment.

Exploration and Production

The Company explores for, develops and produces oil and natural gas reserves, with a primary focus on increasing its reserves and production in the Mid-Continent and Permian Basin. The Company operates substantially all of its wells in these areas and also operates leasehold positions in the WTO, Gulf Coast and Gulf of Mexico.

MANAGEMENT DISCUSSION FROM LATEST 10K

Exploration and Production Segment

The Company currently generates the majority of its consolidated revenues and cash flow from the production and sale of oil and natural gas. The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on the Company’s ability to find and economically develop and produce oil and natural gas reserves. Prices for oil and natural gas fluctuate widely. In order to reduce the Company’s exposure to these fluctuations, the Company enters into commodity derivative contracts for a portion of its anticipated future oil and natural gas production. Reducing the Company’s exposure to price volatility helps ensure that it has adequate funds available for its capital expenditure programs.

The average price received for the Company’s oil production increased 24.4%, or $16.32 per barrel, to $83.21 per barrel during the year ended December 31, 2011 from $66.89 per barrel during 2010. The average price received for the Company’s natural gas production for the year ended December 31, 2011 decreased 4.9%, or $0.18 per Mcf, to $3.50 per Mcf from $3.68 per Mcf in 2010.

Due to the long-term nature of the Company’s investment in the development of its properties, the Company enters into oil and natural gas swaps and collars for a portion of its production in order to stabilize future cash inflows for planning purposes. The Company’s derivative contracts are not designated as accounting hedges and, as a result, realized and unrealized gains or losses on commodity derivative contracts are recorded as a component of operating expenses. Internally, management views the settlement of such derivative contracts as adjustments to the price received for oil and natural gas production to determine “effective prices.” Realized gains or losses from the settlement of derivative contracts with contractual maturities outside of the reporting period are not considered in the calculation of effective prices. The effective price received for oil for the year ended December 31, 2011 was $76.41 per Bbl compared to $68.15 per Bbl during 2010. The effective price received for natural gas for the year ended December 31, 2011 was $3.27 per Mcf compared to $6.20 per Mcf during 2010. This decrease in the effective price received for natural gas is primarily due to not having natural gas fixed price swap contracts in place for a majority of natural gas production in 2011.

During the year ended December 31, 2011, the exploration and production segment reported a $44.1 million net gain on its commodity derivative positions ($50.7 million realized loss and $94.8 million unrealized gain) compared to a $50.9 million net loss on its commodity derivative positions ($224.3 million realized gain and $275.2 million unrealized loss) in 2010. The realized loss for the year ended December 31, 2011 was primarily due to higher oil prices at the time of settlement compared to the contract price on the Company’s oil price swaps. Net realized gains totaling $48.1 million ($111.0 million realized gains and $62.9 million realized losses) resulting from settlements of commodity derivative contracts with original contractual maturities after the quarterly period in which they were settled (“out-of-period settlements”) were included in the net realized loss for the year ended December 31, 2011. The realized gain for the year ended December 31, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price on the Company’s natural gas price swaps. Realized gains totaling $114.4 million resulting from out-of-period settlements were included in the realized gain for the year ended December 31, 2010. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on the Company’s commodity derivative contracts recorded during the year ended December 31, 2011 was primarily attributable to existing contract prices on the Company’s oil price swaps exceeding average oil market prices as of December 31, 2011. The unrealized loss on commodity contracts recorded during the year ended December 31, 2010 was attributable to an increase in average oil prices and decreases in the price differentials on the Company’s natural gas basis swaps at December 31, 2010 compared to the average oil prices and price differentials at December 31, 2009 or the contract price for contracts entered into during 2010.

For the year ended December 31, 2011, the Company had income from operations of $521.1 million in its exploration and production segment compared to $88.4 million in 2010. An increase of $452.0 million in oil and natural gas revenues was slightly offset by increases of $85.0 million in production expense, $16.9 million in production taxes and $51.3 million in depreciation and depletion on oil and natural gas properties during the year ended December 31, 2011. Additionally, the Company recorded a $44.1 million net gain on its commodity derivative contracts for the year ended December 31, 2011 compared to a $50.9 million net loss in 2010. See further discussion of these changes under “Consolidated Results of Operations” below.

Exploration and Production Segment—Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Exploration and production segment revenues increased $322.1 million, or 70.5%, to $779.2 million in the year ended December 31, 2010 from $457.1 million in 2009, primarily as a result of the 155.2% increase in oil production, slightly offset by the 12.8% decrease in natural gas production volumes. Also contributing to the increase was a 48.1% increase in the combined average price the Company received on its oil and natural gas production. In the year ended December 31, 2010, oil production increased by 4,492 MBbls to 7,386 MBbls. The increase in oil production was due to the addition of Permian Basin properties acquired from Forest and Arena, and a focus on increased oil drilling in 2010. The Company produced 3,774 MBbls of oil for the year ended December 31, 2010 from the properties acquired from Forest and Arena. The 11.2 Bcf decrease in natural gas production was a result of the decline in the number of rigs drilling for natural gas during 2010 due to depressed natural gas prices and the Company’s strategic shift to increased oil drilling.

The average price received for the Company’s oil production increased 20.3%, or $11.27 per barrel, to $66.89 per barrel during the year ended December 31, 2010 from $55.62 per barrel in 2009. The average price the Company received for its natural gas production for the year ended December 31, 2010 increased 9.5%, or $0.32 per Mcf, to $3.68 per Mcf from $3.36 per Mcf in 2009. Including the impact of derivative contract settlements, the effective price received for oil for the year ended December 31, 2010 was $68.15 per Bbl compared to $59.69 per Bbl in 2009. Including the impact of derivative contract settlements, the effective price received for natural gas for the year ended December 31, 2010 was $6.20 per Mcf compared to $7.20 per Mcf in 2009.

During the year ended December 31, 2010, the exploration and production segment reported a $50.9 million net loss on its commodity derivative positions ($224.3 million realized gain and $275.2 million unrealized loss) compared to a $147.5 million net gain on its commodity derivative positions ($348.0 million realized gain and $200.5 million unrealized loss) in 2009. The realized gain of $224.3 million for the year ended December 31, 2010 was primarily due to lower natural gas prices at the time of settlement compared to the contract price. Realized gains totaling $114.4 million resulting from out-of-period settlements were included in the realized gain for the year ended December 31, 2010. The unrealized loss on the Company’s commodity contracts recorded during the year ended December 31, 2010 was primarily attributable to an increase in average oil prices at December 31, 2010 compared to the average oil prices at December 31, 2009 or the contract price for contracts entered into during 2010 and the settlement of natural gas price swaps during the year ended December 31, 2010. The unrealized loss for the year ended December 31, 2009 was attributable to increased average oil and natural gas prices and decreases in the price differentials on the Company’s basis swaps at December 31, 2009.

For the year ended December 31, 2010, the Company had income from operations of $88.4 million in its exploration and production segment compared to a loss from operations of $1,487.9 million in 2009. The $320.1 million increase in oil and natural gas revenues and the absence of a full cost pool ceiling impairment were partially offset by the $50.9 million net loss on commodity derivative contracts, a $68.0 million increase in production expenses, a $25.2 million increase in production taxes and a $99.3 million increase in depreciation and depletion on oil and natural gas properties. See discussion of production expense, production taxes and depreciation and depletion under “Consolidated Results of Operations” below.

Drilling and Oil Field Services Segment

The financial results of the Company’s drilling and oil field services segment depend primarily on demand and prices that can be charged for its services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third-party working interests in wells the Company operates, are included in drilling and services revenues and expenses. Drilling and oil field service revenues earned and expenses incurred in performing services for the Company’s own account are eliminated in consolidation.

Midstream Gas Services Segment

Midstream gas services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business. Midstream gas services are primarily undertaken to realize incremental margins on natural gas purchased at the wellhead, and provide value-added services to customers. On a consolidated basis, midstream and marketing revenues represent natural gas sold on behalf of third parties and the fees the Company charges to gather, compress and treat this natural gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of natural gas owned by such parties, net of any applicable margin and actual costs the Company charges to gather, compress and treat the natural gas. In general, natural gas purchased and sold by the Company’s midstream gas business is priced at a published daily or monthly index price. The primary factors affecting the results of the Company’s midstream gas services segment are the quantity of natural gas the Company gathers, treats and markets and the prices it pays and receives for natural gas.

In June 2009, the Company completed the sale of its gathering and compression assets located in the Piñon Field. Net proceeds from the sale were approximately $197.5 million, which resulted in a loss on the sale of $26.1 million. In conjunction with the sale, the Company entered into a gas gathering agreement and an operations and maintenance agreement. Under the gas gathering agreement, the Company has dedicated its Piñon Field acreage for priority gathering services through June 30, 2029 and will pay a fee for such services that was negotiated at arms’ length. Pursuant to the operations and maintenance agreement, the Company will operate and maintain the gathering system assets sold through June 30, 2029 unless the Company or the buyer of the assets chooses to terminate the agreement.

Grey Ranch Plant, L.P. (“GRLP”) is a limited partnership that operates the Company’s Grey Ranch plant located in Pecos County, Texas. The Company purchased its 50% interest in GRLP during 2003. During October 2009, the Company executed amendments to certain agreements related to the ownership and operation of GRLP. As a result of these amendments, the Company became the primary beneficiary of GRLP and began consolidating the activity of GRLP in its midstream gas services segment prospectively beginning on October 1, 2009, the effective date of the amendments.

Midstream Gas Services Segment—Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Midstream gas services segment revenues for the year ended December 31, 2011 were $65.2 million compared to $98.5 million in 2010. The decrease in revenue was due to a decrease in third-party volumes the Company marketed of approximately 5.5 Bcf, a decrease in natural gas prices and a decrease in natural gas volumes processed in the Company’s gas treating plants. The decrease in revenue and a $2.8 million impairment on certain midstream assets resulted in a loss from operations of $13.0 million for the year ended December 31, 2011 compared to income from operations of $4.0 million in 2010.

Midstream Gas Services Segment—Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Midstream gas services segment revenues for the year ended December 31, 2010 were $98.5 million compared to $83.9 million in the same period in 2009. Income from operations was $4.0 million for the year ended December 31, 2010 compared to a loss from operations of $37.0 million in 2009. An increase in natural gas prices for third-party volumes the Company marketed in the year ended December 31, 2010 compared to 2009 contributed to the increase in revenues. The consolidation of GRLP activity into the midstream gas services segment for the year ended December 31, 2010 also contributed to the increase in midstream gas services segment revenues and to the increase in income from operations. Prior to October 1, 2009 when the Company began consolidating GRLP, its share of GRLP activity was reported as income from equity investments. The 2010 increase in income from operations was primarily due to the inclusion of a $26.1 million loss on the sale of the Company’s gathering and compression assets and a $10.0 million impairment on its spare parts inventory in the year ended December 31, 2009.

Liquidity and Capital Resources

The Company’s primary sources of liquidity and capital resources are cash flow generated from operations, borrowings under the Company’s senior credit facility, the issuance of equity and debt securities and proceeds from sales or other monetization of assets. As described in Item 1 “Business—2011 Developments,” during 2011, the Company raised approximately $2.0 billion, net of certain fees, post-closing adjustments and redemptions, through royalty trust offerings, asset monetizations and senior note issuances. Additionally, as described in Item 1 “Business—2012 Developments,” the Company received approximately $272.5 million in January 2012 from the sale of working interests in the Mississippian formation, and could realize proceeds from the proposed Mississippian Trust II offering in 2012.

The Company’s primary uses of capital are expenditures related to its oil and natural gas properties, such as costs related to drilling and completion of wells, including to fulfill its drilling commitments to the royalty trusts, and other fixed assets, the acquisition of oil and natural gas properties, the repayment of amounts outstanding on its senior credit facility, the payment of dividends on its outstanding convertible perpetual preferred stock and interest payments on its outstanding debt. The Company maintains access to funds that may be needed to meet capital funding requirements through its senior credit facility.

Working Capital

The Company’s working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under its senior credit facility and changes in the fair value of its outstanding commodity derivative instruments. Absent any significant effects from its commodity derivative instruments, the Company typically maintains a working capital deficit or a relatively small amount of positive working capital because the Company’s capital spending generally has exceeded the Company’s cash flows from operations and it generally uses excess cash to pay down borrowings outstanding under its credit arrangements.

At December 31, 2011, the Company had a working capital deficit of $257.7 million compared to a deficit of $368.9 million at December 31, 2010. Current assets increased $266.3 million at December 31, 2011, compared to current assets at December 31, 2010, primarily due to a $201.8 million increase in cash and cash equivalents, as a result of proceeds received in November 2011 from the sale of the Company’s east Texas properties, and a $60.2 million increase in accounts receivable due to an increase in oil production and prices received on oil production. Current liabilities increased $155.0 million, primarily due to a $129.9 million increase in accounts payable and accrued expenses resulting from increased production and drilling activity.

The Company expects to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2012 from cash flows from operating activities, its existing cash balances, availability under its senior credit facility, proceeds from the sale of working interests in the Mississippian formation in January 2012, proceeds from the proposed Mississippian Trust II offering, other potential monetizations of assets and potential access to capital markets. However, a significant portion of the Company’s 2012 capital expenditures budget is discretionary and can be curtailed, if necessary, based on oil and natural gas prices and the availability of the sources of funds described above.

The Company’s operating cash flow is mainly influenced by the prices the Company receives for its oil and natural gas production; the quantity of oil and natural gas it produces; settlements on derivative contracts; third-party demand for its drilling rigs and oil field services and the rates it is able to charge for these services; and the margins it obtains from its natural gas and CO 2 gathering and treating contracts.

Net cash provided by operating activities for the years ended December 31, 2011 and 2010 was $475.5 million and $390.1 million, respectively. The increase in cash provided by operating activities in 2011 compared to 2010 was primarily due to an increase in oil sales as a result of increased oil production and prices received for oil production, partially offset by a decrease in natural gas sales as a result of decreased natural gas production and realized losses on the Company’s commodity derivative contracts in 2011 compared to realized gains in 2010.

Net cash provided by operating activities for the years ended December 31, 2010 and 2009 was $390.1 million and $311.6 million, respectively. The increase in cash provided by operating activities in 2010 compared to 2009 was primarily due to a 48.1% increase in the average prices the Company received for its oil and natural gas production, and increased oil production resulting from the properties acquired from Forest and Arena and a focus on increased oil drilling in 2010.

Cash Flows from Investing Activities

The Company dedicates and expects to continue to dedicate a substantial portion of its capital expenditure program toward the development, production and acquisition of oil and natural gas reserves. These capital expenditures are necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and natural gas industry.

Cash flows used in investing activities decreased to $918.9 million in the year ended December 31, 2011 from $962.8 million in 2010 due to increased proceeds from the sale of assets during the period, partially offset by an increase in capital expenditures, primarily for the continued development of the Company’s oil and natural gas properties. Proceeds from asset sales, including the sale of working interests to Atinum, during 2011 totaled $859.4 million compared to $205.0 million in 2010.

Cash flows used in investing activities decreased to $962.8 million in the year ended December 31, 2010 from $1,247.1 million in 2009 primarily due to the use of equity to fund the majority of the Arena Acquisition in July 2010 rather than cash, which was used to purchase the properties acquired from Forest in 2009. This was partially offset by increased capital expenditures during 2010.

Cash Flows from Financing Activities

The Company’s financing activities provided $645.2 million in cash for the year ended December 31, 2011 compared to $570.6 million in 2010. Cash provided by financing activities during 2011 was primarily comprised of $880.6 million of net proceeds from the issuance of the 7.5% Senior Notes and $917.5 million of net proceeds from the conveyance of royalty interests to the Mississippian Trust I and the Permian Trust. These amounts were partially offset by the purchase and redemption of $650.0 million aggregate principal amount of the 8.625% Senior Notes, as well as the premium paid on extinguishment of $30.3 million in connection with the purchase and redemption, $340.0 million of net repayments under the senior credit facility, $57.4 million of distributions to third-party royalty trust unitholders and $56.7 million of dividends paid on the Company’s convertible perpetual preferred stock.

The Company’s financing activities provided $570.6 million in cash for the year ended December 31, 2010 compared to $942.7 million in 2009. Cash provided by financing activities during 2010 was primarily comprised of $328.0 million of net borrowings, representing borrowings under the Company’s senior credit facility reduced by payments on its debt and $290.7 million of net proceeds from the issuance of 3,000,000 shares of the Company’s 7.0% convertible perpetual preferred stock, offset slightly by the payment of dividends on its 8.5% convertible perpetual preferred stock and its 6.0% convertible perpetual preferred stock and debt issuance costs. Cash provided by financing activities during the year ended December 31, 2009 was generated primarily by the private placements of an aggregate of 4,650,000 shares of the Company’s convertible perpetual preferred stock and the registered underwritten offering of 40,080,000 shares common stock that provided combined proceeds of approximately $768.0 million, the majority of which were used to pay down amounts outstanding under the senior credit facility.

Indebtedness

Senior Credit Facility. The amount the Company may borrow under its senior credit facility is limited to a borrowing base, and is subject to periodic redeterminations. The Company pays a 0.5% commitment fee on any available portion of the senior credit facility. Effective March 15, 2011, the borrowing base was reduced to $790.0 million due to the issuance of the Company’s 7.5% Senior Notes. The borrowing base is determined based upon the discounted present value of future cash flows attributable to the Company’s proved reserves. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. Outstanding letters of credit affect the availability under the senior credit facility on a dollar-for-dollar basis. The senior credit facility matures on April 15, 2014, unless the Company’s Senior Floating Rate Notes due 2014 (“Senior Floating Rate Notes”) have not been refinanced by December 31, 2013, in which case the senior credit facility will mature on January 31, 2014.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Overview of the Company

SandRidge is an independent oil and natural gas company concentrating on development and production activities related to the exploitation of the Company’s significant holdings in West Texas and the Mid-Continent area of Oklahoma and Kansas. The Company’s primary areas of focus are the Permian Basin in West Texas and the Mississippian formation in the Mid-Continent. The Company also owns and operates other interests in the Mid-Continent, WTO, Gulf Coast and Gulf of Mexico. During 2010 and 2011, the Company has continued the expansion of its oil property base through the Arena Acquisition in July 2010, which added significantly to the Company’s holdings in the Permian Basin, and through the growth and development of its property base in the Mid-Continent area of Oklahoma and Kansas. The Company consolidates the activities of the Mississippian Trust and the Permian Trust, two publicly traded royalty trusts described below and in Note 8 to the Company’s unaudited condensed consolidated financial statements.

The Company operates businesses that are complementary to its development and production activities. The Company owns related gas gathering and treating facilities, a gas marketing business and an oil field services business. The extent to which each of these supplemental businesses contributes to the Company’s consolidated results of operations largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by these businesses for the Company’s own account are eliminated in consolidation and, therefore, do not directly contribute to the Company’s consolidated results of operations.

The Company currently generates the majority of its consolidated revenues and cash flow from the production and sale of oil and natural gas. The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on the Company’s ability to find and economically develop and produce oil and natural gas reserves. Prices for oil and natural gas fluctuate widely. In order to reduce the Company’s exposure to these fluctuations, the Company enters into commodity derivative contracts for a portion of its anticipated future oil and natural gas production. Reducing the Company’s exposure to price volatility helps ensure that it has adequate funds available for its capital expenditure programs.

SandRidge Mississippian Trust I. On April 12, 2011, the Mississippian Trust completed its initial public offering of 17,250,000 common units representing a 61.6% beneficial interest in the Mississippian Trust. Net proceeds to the Mississippian Trust, after certain offering expenses, were approximately $336.9 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Mississippian Trust in exchange for the net proceeds of the Mississippian Trust’s initial public offering and 10,750,000 units representing approximately 38.4% of the beneficial interest in the Mississippian Trust. The Company used the net proceeds it received from the Mississippian Trust’s offering to repay borrowings under the Company’s senior credit facility and for general corporate purposes.

SandRidge Permian Trust. On August 16, 2011, the Permian Trust completed its initial public offering of 34,500,000 common units representing a 65.7% beneficial interest in the Permian Trust. Net proceeds to the Permian Trust, after certain offering expenses, were approximately $580.6 million. Concurrent with the closing, the Company conveyed certain royalty interests to the Permian Trust in exchange for the net proceeds of the Permian Trust’s initial public offering and 18,000,000 units representing approximately 34.3% of the beneficial interest in the Permian Trust. The Company used the net proceeds it received from the Permian Trust’s initial public offering to repay borrowings under the Company’s senior credit facility and plans to use remaining proceeds for general corporate purposes.

Recent Developments

Sale of Working Interest in Mississippian Properties. In September 2011, the Company sold to Atinum 13.2% of its working interest in approximately 860,000 acres the Company has leased in the Mississippian formation in the Mid-Continent. As consideration for the working interest, Atinum paid the Company approximately $270.7 million in cash (including approximately $4.9 million attributable to the Atinum drilling carry and approximately $7.7 million not attributable to the Atinum drilling carry, but to be applied against the Company’s future capital expenditures on the properties) and committed to pay 13.2% of SandRidge’s share of drilling and completion costs for wells drilled within an area of mutual interest until an additional $250.0 million has been paid, which is expected to occur over a three-year period. The Company plans to use the proceeds to fund a portion of its drilling program and for general corporate purposes.

Sale of East Texas Properties. In September 2011, the Company agreed to sell its East Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $231.0 million, subject to post closing adjustments. The Company expects the transaction to close in the fourth quarter of 2011 and intends to use the cash proceeds to fund a portion of its drilling program and for general corporate purposes.

7.5% Senior Notes Registered Exchange Offer. In conjunction with the issuance of the Company’s 7.5% Senior Notes, the Company entered into a Registration Rights Agreement requiring the Company to conduct a registered exchange offer for or register the resale of these notes before March 14, 2012. On October 17, 2011, the Company commenced a registered exchange offer for the 7.5% Senior Notes. See further discussion in Note 11 to the Company’s unaudited condensed consolidated financial statements included in this Quarterly Report.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements, see Note 2 to the Company’s condensed consolidated financial statements included in Item 1 of this Quarterly Report.

Exploration and Production Segment — Three months ended September 30, 2011 compared to the three months ended September 30, 2010

Exploration and production segment revenues increased $111.0 million, or 52.7%, to $321.4 million in the three months ended September 30, 2011 from $210.4 million in the three months ended September 30, 2010, as a result of a 43.8% increase in oil production and a 24.1% increase in the average price the Company received for its oil production. These increases were slightly offset by a 6.1% decrease in natural gas production. The increase in oil production was due to the continued development of Permian Basin properties acquired from Arena, and a focus on increased oil drilling in the Permian Basin and Mid-Continent throughout 2010 and 2011. Properties acquired and developed from Arena produced 1,122 MBbls of oil for the three-month period ended September 30, 2011, compared to 680 MBbls in the 2010 period. The decrease in natural gas production was a result of natural production declines in existing natural gas wells.

The average price received for the Company’s oil production increased 24.1%, or $15.41 per barrel, to $79.31 per barrel during the three months ended September 30, 2011 from $63.90 per barrel during the same period in 2010. The average price received for the Company’s natural gas production for the three-month period ended September 30, 2011 increased 2.0%, or $0.07 per Mcf, to $3.64 per Mcf from $3.57 per Mcf in the comparable period in 2010. Including the impact of derivative contract settlements, the effective price received for oil for the three-month period ended September 30, 2011 was $76.94 per Bbl compared to $64.74 per Bbl during the same period in 2010. Including the impact of derivative contract settlements, the effective price received for natural gas for the three-month period ended September 30, 2011 was $3.08 per Mcf compared to $5.02 per Mcf during the same period in 2010. The Company’s derivative contracts are not designated as hedges and, as a result, realized and unrealized gains or losses on commodity derivative contracts are recorded as a component of operating expenses. Internally, management views the settlement of such derivative contracts as adjustments to the price received for oil and natural gas production to determine “effective prices.” Realized gains or losses from the settlement of derivative contracts with contractual maturities outside of the reporting period are not considered in the calculation of “effective prices.”

During the three-month period ended September 30, 2011, the exploration and production segment reported a $596.7 million net gain on its commodity derivative positions ($7.8 million realized loss and $604.5 million unrealized gain) compared to a $67.2 million net loss on its commodity derivative positions ($77.7 million realized gain and $144.9 million unrealized loss) in the same period in 2010. Net realized gains totaling $9.9 million ($72.8 million realized gains and $62.9 million realized losses) on out-of-period settlements were included in the net realized loss for the three months ended September 30, 2011. Realized gains totaling $48.2 million on out-of-period settlements were included in the net realized gain for the three-month period ended September 30, 2010. Realized gains or losses on derivative contracts represent the difference in the settlement price compared to the contract price. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized gain on the Company’s commodity derivative contracts recorded during the three months ended September 30, 2011 was primarily attributable to a decrease in average oil prices at September 30, 2011 compared to the average oil prices at June 30, 2011 or the contract price for contracts entered into during the third quarter of 2011. The unrealized loss on the Company’s commodity contracts recorded during the three months ended September 30, 2010 was primarily attributable to an increase in average oil prices at September 30, 2010 compared to the average oil prices at June 30, 2010.

For the three months ended September 30, 2011, the Company had operating income of $717.3 million in its exploration and production segment compared to an operating loss of $65.6 million for the same period in 2010. An increase of $108.5 million in oil and natural gas revenues was partially offset by an increase of $20.5 million in production expense during the three months ended September 30, 2011. Additionally, the Company recorded a $596.7 million net gain on commodity derivative contracts for the three months ended September 30, 2011 compared to a $67.2 million net loss for the same period in 2010. See further discussion of these changes under “Consolidated Results of Operations.”

Exploration and Production Segment — Nine months ended September 30, 2011 compared to the nine months ended September 30, 2010

Exploration and production segment revenues increased $375.2 million, or 70.7%, to $906.3 million in the nine months ended September 30, 2011 from $531.0 million in the nine months ended September 30, 2010, as a result of a 78.9% increase in oil production and a 28.7% increase in the average price the Company received for its oil production. These increases were slightly offset by an 8.8% decrease in natural gas production and a 5.7% decrease in the average price received for natural gas production. The increase in oil production was due to the addition of Permian Basin properties acquired from Arena in July 2010, and the continued focus on increased oil drilling throughout 2010 and 2011. Properties acquired and developed from Arena produced 2,973 MBbls of oil for the nine-month period ended September 30, 2011 compared to 680 MBbls in the 2010 period after the acquisition. The decrease in natural gas production was a result of natural production declines in existing natural gas wells.

The average price received for the Company’s oil production increased 28.7%, or $18.43 per barrel, to $82.61 per barrel during the nine months ended September 30, 2011 from $64.18 per barrel during the same period in 2010. The average price received for the Company’s natural gas production for the nine-month period ended September 30, 2011 decreased 5.7%, or $0.22 per Mcf, to $3.66 per Mcf from $3.88 per Mcf in the comparable period in 2010. Including the impact of derivative contract settlements, the effective price received for oil for the nine-month period ended September 30, 2011 was $75.30 per Bbl compared to $67.12 per Bbl during the same period in 2010. Including the impact of derivative contract settlements, the effective price received for natural gas for the nine-month period ended September 30, 2011 was $3.41 per Mcf compared to $6.30 per Mcf during the same period in 2010.

During the nine-month period ended September 30, 2011, the exploration and production segment reported a $489.1 million net gain on its commodity derivative positions ($34.7 million realized loss and $523.8 million unrealized gain) compared to a $114.4 million net gain on its commodity derivative positions ($238.2 million realized gain and $123.8 million unrealized loss) in the same period in 2010. Net realized gains totaling $48.1 million ($111.0 million realized gains and $62.9 million realized losses) on out-of-period settlements were included in the net realized loss for the nine months ended September 30, 2011. Realized gains on out-of-period settlements totaling $110.6 million were included in the net realized gain for the nine months ended September 30, 2010. The unrealized gain on the Company’s commodity derivative contracts recorded during the nine months ended September 30, 2011 was primarily attributable to a decrease in average oil prices at September 30, 2011 compared to the average oil prices at December 31, 2010 or the contract price for contracts entered into during 2011. The unrealized loss on commodity contracts recorded during the nine months ended September 30, 2010 was attributable to an increase in average oil prices and decreases in the price differentials on the Company’s natural gas basis swaps at September 30, 2010 compared to the average oil prices and price differentials at December 31, 2009 or the contract price for contracts entered into during 2010.

For the nine months ended September 30, 2011, the Company had operating income of $834.3 million in its exploration and production segment compared to operating income of $180.8 million for the same period in 2010. Increases of $367.9 million in oil and natural gas revenues and $374.7 million in gain on derivative contracts were slightly offset by increases of $70.0 million in production expense, $14.5 million in production taxes and $39.0 million in depreciation and depletion on oil and natural gas properties during the nine months ended September 30, 2011. See further discussion of these changes under “Consolidated Results of Operations.”

Drilling and Oil Field Services Segment

The financial results of the Company’s drilling and oil field services segment depend primarily on demand and prices that can be charged for its services. In addition to providing drilling services, the Company’s oil field services business also conducts operations that complement its exploration and production segment such as providing pulling units, trucking, rental tools, location and road construction and roustabout services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third party working interests in wells the Company operates, are included in drilling and services revenues and expenses while drilling and oil field service revenues earned and expenses incurred in performing services for the Company’s own account are eliminated in consolidation.

Drilling and Oil Field Services Segment — Nine months ended September 30, 2011 compared to the nine months ended September 30, 2010

Drilling and oil field services segment revenues increased to $75.1 million in the nine-month period ended September 30, 2011 from $14.9 million in the nine-month period ended September 30, 2010 and drilling and oil field services segment expenses increased $47.3 million during the same period to $68.6 million. The increase in revenue resulted in operating income of $6.5 million in the nine-month period ended September 30, 2011 compared to an operating loss of $6.4 million for the same period in 2010. The increase in revenues and expenses was primarily attributable to an increase in the number of rigs working for third parties and an increase in oil field services performed for third parties during the 2011 period.

Midstream Gas Services Segment

Midstream gas services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business. Midstream gas services are primarily undertaken to realize incremental margins on natural gas purchased at the wellhead, and provide value-added services to customers. On a consolidated basis, midstream and marketing revenues represent natural gas sold on behalf of third parties and the fees the Company charges to gather, compress and treat this natural gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of natural gas owned by such parties, net of any applicable margin and actual costs the Company charges to gather, compress and treat the natural gas. In general, natural gas purchased and sold by the Company’s midstream gas business is priced at a published daily or monthly index price. The primary factors affecting the results of the Company’s midstream gas services segment are the quantity of natural gas the Company gathers, treats and markets and the prices it pays and receives for natural gas.

The Company owns and operates two gas treating plants in West Texas, which remove CO 2 from natural gas production and deliver residue gas to nearby pipelines. During 2011, the Company continued with the operational assessment phase of the Century Plant, in Pecos County, Texas, including diverting some of the Company’s natural gas from the Company’s two existing gas treating plants and processing it at the Century Plant during this time. As a result of this assessment, the Century Plant has been taken off line from time to time to resolve certain operational issues. The Company is currently in the process of diverting its high CO 2 natural gas production back through the Century Plant and commencing performance testing for Train I of the Century Plant. Upon successful completion of the performance testing, the use of the Company’s two gas treating plants in West Texas may be limited, the extent of which will depend on certain variables, including natural gas prices and the expected need for such plants to supplement treating capacity at the Century Plant going forward. During the second quarter of 2011, the Company evaluated its gas treating plants for impairment in connection with the operational phase of Train I of the Century Plant and concluded no impairment was necessary.

Midstream Gas Services Segment — Three months ended September 30, 2011 compared to the three months ended September 30, 2010

Midstream gas services segment revenues for the three months ended September 30, 2011 were $14.7 million compared to $22.9 million in the same period in 2010. The decrease in revenue along with the impact of fixed charges necessary to maintain and operate the treating plants resulted in an operating loss of $2.0 million for the three months ended September 30, 2011 compared to operating income of $1.2 million for the comparable period in 2010. The decrease in revenue was due to a decrease in third party volumes the Company marketed and a decrease in natural gas volumes processed in the Company’s gas treating plants.

Midstream Gas Services Segment — Nine months ended September 30, 2011 compared to the nine months ended September 30, 2010

Midstream gas services segment revenues for the nine months ended September 30, 2011 were $52.4 million compared to $72.6 million in the same period in 2010. The decrease in revenue along with the impact of fixed charges necessary to maintain and operate the treating plants resulted in an operating loss of $7.1 million for the nine months ended September 30, 2011 compared to operating income of $3.4 million for the comparable period in 2010. The decrease in revenue was due to a decrease in third party volumes the Company marketed, a decrease in natural gas prices and a decrease in natural gas volumes processed in the Company’s gas treating plants.

CONF CALL

SandRidge Energy, Inc. - Shareholder/Analyst Call
February 28, 2012 | about: SD

Presentation
Q&A
Participants

Kevin R. White

Good morning, and welcome to the SandRidge Analyst Day. We've got a big crowd today. So welcome, and hope everybody enjoys the day, and more importantly, the buckyballs. I want to take a quick second to introduce our Board of Directors. And for the board, if you guys could stay standing up after I call you. We got -- excuse me, Jim J. Brewer; Everett Dobson, you've seen Everett this morning; Bill Gilliland; Dan Jordan, he's right over here; and Roy Oliver. So that's the SandRidge Board of Directors, and welcome to those guys.

I just wanted to go through what the agenda is going to look like today, and you can see the forward-looking statements on the first page there. For the day today, we've got Tom, who's going to lead us off with some introductory comments, and Matt, who will go over high-level operations review. Todd Tipton and Rodney Johnson will go over the Extension Mississippian and the original Mississippian technical overview. Dave Lawler will go through our development plan for 2012. And then after Dave is done, we're going to take a short break at that time. And then finish up the day with Rodney Johnson going over the company's year-end reserves and James Bennett wrapping up with our finance overview.

Another thing I wanted to point out, in your book, we've got guidance for 2012 in the back of the book in the appendix. And we don't have any plans to go over the information specifically today, but if you've questions, feel free to ask about it. And through the course of the presentation today, most of the information that is presented, is presented as SandRidge only, so it's pre our Dynamic acquisition. There'll be some slides through the course of the day where we will have footnoted it and noted when we've included Dynamic's information in some of our numbers. And then in the guidance information that's at the back of the table, we have included Dynamic assuming a close of April 30.

So with that brief overview, we'll let Tom come up and get started.

Tom L. Ward

Thanks, Kev. I was running just a little bit late this morning. I was on the phone with my counterpart in Nigeria, looking a little bit of cheap oil. Just kidding, just kidding, I was just kidding. So a few years ago, as we started looking at the transition of the company from gas to oil, we had some big objectives, how do we move the company forward? But more -- and just the last year, we started to focus down. And whenever I looked at the growth of the Mississippian project, what I kept seeing in our model was that 3 years out, things were really very good for us as long as we could do some transactions to get us there, as long as we could keep our CapEx up at a $1.6 billion to $2 billion range. There were some objectives that we could reach that I thought would be different than most companies were able to achieve. So those objectives were tripling EBITDA, doubling our oil production, having a company that is mature. In my definition, mature is you could have a couple of billion dollars of CapEx that can be funded within cash flow, then you're looking at making acquisitions that would be funded with straight debt and equity. So that's kind of the goal post-2014 as whenever I think of SandRidge as a mature company.

Now keep in mind, we're only 5 years old. And with that 5 years, we had a U-turn in the middle where we moved from a 95% natural gas company to today by PV, we drill basically 94% oil. So it is a very rapid growth we've had, and that we've been able to achieve that in a short amount of time is -- a lot of credit is given to the guys in our organization you'll be hearing from today. I'm going to keep my presentation very short and try to just give the strategic overview of the company, but I want to spend most of the day will be with Matt and Dave, Todd and Rodney and James. And so what I do want to focus on that along with being able to have tripling of EBITDA and doubling of oil production is that we'll continue to make transactions and improve our credit metrics.

There's really not much that's changed for the company post-Dynamic. We still are low-risk, shallow conventional oil. We're really focusing on the 2 best areas from a rate of return perspective in the U.S. And that's the Mid-Continent and the Mississippian play, and the Permian is where we drill all of our wells basically, or onshore looking for shallow conventional oil out of carbonates. The Dynamic transaction doesn't change that. In fact, it just helps us with our growth engine of being the main drilling part of the company in the Mid-Continent.

Much like what we did in the Permian basin in 2009, when we moved into the Permian, it was an out-of-favor area. We looked at places that were being drilled shallow, very shallow oil. Most of the wells that were drilled and still are drilled on the Central Basin Platform are at 4,000 feet or so of vertical wells being drilled. And so what we looked at, it was a way, can we logistically drill 600 to 800 wells a year and can we take something that is known that there's oil in place and make an acquisition, and on around that acquisition, build an oil company. And that's what we did with our -- starting in 2009. When we met right here in March of 2009 and our board was here then, that was a decision point we had to go forward to oil. And oil was at $39.96 and gas was at $4.13, and that was the transitioning date basically 3 years ago today that we looked back and said, we want to change the company. And with that, we had a net investment in our Permian assets of $1.4 billion. It has a PV-10 value of growth of $2.7 billion so a growth in investment of over $1 billion in that time period. We think the Dynamic transaction we just made is like this, not the growth engine of the Permian, but that we went and bought very inexpensive oil in a place that is out-of-favor in the investment public. And so that there was a dislocation in the market just like there was with the Permian assets 3 years ago.

But the main growth area for the company is the Mississippian. For this, we found something that we knew about that others weren't focused on really a few years ago. But starting in 2009 and 2010 with our drilling and basically starting in Alfalfa County, moving to Grant and Woods and now into Comanche County in Kansas. Now you can see the red is where we've drilled, the blue is where others have drilled. We drilled basically half of all the wells in the Mississippian on the horizontal, but the key of the play was done decades before that we got here. And that's the -- there have been 15,000 wells drilled across a very large area, and what were those people looking for? They were looking for very subtle structures. So it's a huge stratigraphic trap, that red area, in the center of the page is the Central Kansas Uplift. There's no Mississippian present there. There's a large stratigraphic trap wrapping around the Central Kansas Uplift with a perfect trap, the Pennsylvanian Unconformity, and the Mississippian is eroding into that Unconformity. So we have newer rocks tipped away from the Central Kansas Uplift and older rocks because of the new rocks have been eroded off as you move towards the Central Kansas Uplift. Rodney and Todd will go into this in great detail, but this is all the same rock as you wrap around from the Nehema Ridge in Central Oklahoma and Central Kansas up to the Los Animas Arch, which is in Eastern Colorado. Those are the 2 structures where the stratigraphic trap is in between, up against the Central Kansas Uplift. The reason that's where your trap is and there's oil in place, the reason it wasn't drilled, is you have to have the ability to move water. And so what our guys will talk about today is the key to the play is this disposal system that we have in place, and what I would call the genius of the idea is that there's oil in place. At high prices, you can move a lot of water and have very high rates of return. And that's what the idea was that gave us the leg up to go put together the acreage.

So what did we do? We spent basically $400 million to buy 2 million acres, around $200 an acre. And we sold 550,000 of that and still -- and created $2.33 billion worth of value. That's through the Mississippian Trust, number one, the joint ventures that we have; and then a second pending royalty trust that James will talk more about. So that leaves us with 1.5 million acres. The implied value of that, 4,236 as we implied $6.35 billion. The resource NAV, so this is an important number, is $23 billion or $15,000 an acre. So whenever I talk about the ability to hold onto more of this acreage and use the Dynamic transaction as a funding mechanism, that's when I talk about the -- being so accretive, the NAV to us. So the Dynamic acquisition complemented the 3-year plan of doubling production, tripling EBITDA and reducing our leverage. So we had a few alternatives that we could've done, I talked about this at the conference call, is we could've -- in moving forward with our plan, we could've just reduced CapEx. We knew if we kept our CapEx as we projected over the next 3 years, we needed some funding. That's always been known. So how are we going to fund it? Well, first of all, you could've reduced CapEx and just not needed the funding. But then we wouldn't have had the growth and -- that we're projecting in our EBITDA, where you could have -- you could've raised debt, just fund it all with debt, but we were already 4x leveraged. So that wouldn't have been -- this wouldn't have been the appropriate time to be adding debt. We could've issued straight equity. I had a lot of people calling to say, you should just issue straight equity, and frankly, with straight equity, you wouldn't have liked that either. And you would have been -- you wouldn't have had 25,000 barrels of oil a day. So that leaves -- the royalty trust is a good idea, so you could've done more royalty trust, but they're actually fairly small in scale. And you have to sell the most proven assets, so around the production that you have, and you're also selling EBITDA at the same time. It's a good structure, but not one that you could -- that I believe you could build the company going forward over the 3-year plan.

And then the one that I had the most questions about is why don't you sell more acreage, and the last slide shows you why. It's that if the Mississippian is as successful as I think it's going to be, every acre we hold onto is worth $15,000 and we won't be able to sell it today for $15,000. So the Dynamic transaction -- well, oh no, I forget that we could do mezz debt. I mean, there's a lot of mezzanine or mezzanine financing, and I don't even put that in 1 of the 6 ways, I don't even to put that in as something we considered. But the other was to do an acquisition of Dynamic, and in all ways, that was accretive to us. And so that's how come that we talk about the Dynamic acquisition and 25,000 barrels a day. And the Gulf of Mexico has not been a place that I necessarily wanted to go and have a growth engine and it's not considered to be a growth engine, but we do believe by spending $200 million a year, we can keep our production flat, and we'll spend more time. And, well, even post this quarter once we get the Dynamic acquisition in place, we'll spend much more time talking about what we're going to do there.

2011 was really the key year for us. This was the year that was -- the difficult year to do all the transactions that we had to do, to have 440 -- $410 million of adjusted cash flow from operations and have a $1.833 billion CapEx budget. It took 7 transactions to be able to make that together and we did that without adding to -- straight equity. We didn't have to issue equity, and we didn't increase our leverage. So that was the transitional year for the company. Now in 2012, all the hard work's already been done. So we basically have SDR left, and then we're -- our funding is done. And actually, we can add leverage in '13 and '14 and still improve our credit metrics. So the way I look at this is that we're -- the Dynamic acquisition was one of the last 2 things we need to do in order to fulfill our 3-year plan. So I'm very pleased to be here, and I can't wait for you guys to be able to look -- especially at our Mississippian area and why we thought that the Extension Mississippian is as good as the original. And Rodney and Todd will spend a lot of time today going into that, and we're very excited to put together the plan. And we'll have -- this year, we'll have 26 rigs averaging in the Mississippian. We'll end the year with 5 of those continuing to move up into the Extension Mississippian. And next year, we should end the year of 2013 at 45 rigs in the Mississippian. So it's -- I think we're going to be bringing in about 100,000 jobs to Oklahoma and Kansas. It's a wonderful play, over the next 3 years, of growth for the company that'll allow us to execute our 3-year plan of tripling EBITDA, doubling our oil production and continue to improve our credit metrics.

So with that, I will turn it over to Matt.

Matthew K. Grubb

Thank you, Tom. And good morning, everybody, and welcome. My name is Matt Grubb, I'm the President and Chief Operating Officer for SandRidge. And I have about a dozen slides to go through before we get to the technical part of the presentation.

And 2011 is a great year for us in many fronts, not only on the -- to strengthen our balance sheet, but also on a performance and production, executing on our drilling program. We currently produce about 67,000 barrels of oil equivalent per day, and that's 16% growth in total production year-over-year, and 60% growth in oil production. In 2011, we produced about 11 8 million barrels of oil. And in 2012, with Dynamic, we expect to produce about 18.2 million barrels of oil, so that continues with our strategy to increase oil production within the company. Proved reserves, adjusted for what we produce, which was 23.4 million barrels of oil equivalent, and what we sold during the year, which was about 123 million barrels of oil equivalent, we were up 122% year-over-year. Our 2012 drilling plan is similar to our 2011, which is focusing on the Mississippian play and also on the Permian. We're just going to drill more Mississippian wells this year. We expect to drill 380 Mississippian wells and 759 wells on the Central Basin Platform. In 2012, production guidance, 54% of oil growth is projected for the year.

We operate primarily in 2 areas, which I believe, right now, are 2 of the best areas for developing oil and gas. The Mid-Continent, which is our Mississippian play, covers northern part of Oklahoma and Western Kansas, and of course, our Permian Basin is primarily in the Central Basin Platform. The West Texas Overthrust is at Piñon Field, which is a dry gas area, and we don't plan any activity there this year. Like last year, we didn't do a whole lot there. And then, of course, the Gulf of Mexico now with the Dynamic acquisition, we expect to spend about $200 million in the Gulf this year. So overall, we should drill about 1139 wells and roughly about 1150 -- 1155 wells with the Gulf of Mexico.

As I've mentioned earlier, current production is about 25 -- I'm sorry, 67 million -- 67,000 barrels equivalent per day with Dynamic, which we're projecting to produce 25,000 barrels. That gives you a pro forma of 92,000 barrels equivalent per day. We are -- pre-Dynamic, we're producing about 57% oil currently. And with Dynamic, we produce about 50% of oil so that's in-line with what we're doing. So we expect to produce probably 55% to 57% oil this year, in 2012.

The CapEx -- I'm sorry, the total production guidance, pre-Dynamic, and I think some people missed this because we announced this with the Repsol JV, is 26.5 million barrels equivalent. And with Dynamic having it 8 months out of this year, we expect to produce 5.8 million barrels of oil equivalent, and that's 25,000 barrels equivalent per day adjusted 3 months, down 10% for hurricanes in July, August and September. And so for the year, our guidance is 32.3 million barrels of oil equivalent. And as far as CapEx guidance, we were looking -- as far as E&P, there's another, there's land, and there's midstream, and oilfield service not in these numbers, but for E&P, which includes primarily drilling and workovers, we're expected to spend $1.35 billion and another $200 million with Dynamic, bringing that to $1.55 billion.

Proved reserves, we ended the year with 471 million barrels of oil equivalent. When we bought Dynamic, the reserves at year end is 62 million barrels of oil equivalent, bringing the total up to 533 million barrels of oil equivalent. Percent of oil, as you can see, most of the value, by value is 96% for SandRidge. The Dynamic reserves, 77% of that value is oil, bringing the total company pro forma to 91% oil by value. And then percent developed, we're right at -- close to 50%, developed reserves at SandRidge. Dynamic is 81%, bringing the pro forma number to 53% developed reserves.

From an FCC PV-10 value, we finished the year 2011 at $6.9 billion. Dynamic's bringing on another $1.8 billion, $1.9 billion NPV10, bringing the total company to 1-- I'm sorry, to $8.77 billion. And then, I'll repeat, these reserves of our production ratio in the Permian and the Mississippian, they're fairly long life, 19 years. As you can expect with the Gulf of Mexico, those will be shorter-life reserves at 6.8 years. So it brings the total company, our R/P ratio, to 15.7 years. From an NAV standpoint, SandRidge is $34.5 billion, the bulk of that, about 2/3 is in the Mississippian play. And the bulk of the -- remaining is in the Permian Basin. Dynamic brings on another $2.5 billion for a total NAV of $37 billion for the company.

This is our growth chart dating back to September of 2009. In September 2009, the blue line is the total production, oil and gas, and the green line is just oil. And back in September 2009, we're producing about 80% natural gas, 20% oil. Today, we're producing about 57% oil. And so you can see as we set out back in 2009 to transform our company from natural gas to oil, we bought Forest first back in -- and we closed that in December of 2009. Then 7 months later, we bought Arena, bringing our total oil production up from about 15,000 barrels to about 25,000 barrels of oil. And the rest of that, from July of '10 through February 2012, has been grown organically just through drilling in the Forest and the Arena properties, and the little bit of legacy Central Basin Platform makers that we had. So it's been tremendous growth in oil just over the last couple of years.

The Mississippian. The Mississippian has been truly a remarkable play for us. It is truly a vast area of tremendous resources for developing oil and gas. One of the great things about the play is that it's shallow. TVD on this play, true vertical depth, the top of the Miss. is kind of 5,000 to 6,000 feet. It's as shallow as a thick carbonate, on average probably about 300 feet thick. The area that we looked at leasing in here that we -- the envelope that we drawn in here, covers about 17 million acres, and has been proven up through history with nearly 15,000 vertical wells. So what we have left after the JVs that we've done is 1.5 million net acres, and this represents nearly $24 billion of NAV value. There's approximately 7,000 locations to drill here, and this is based on 3 wells per 640 acre section. And we still -- we started the program thinking we would recover 300,000 to 500,000 barrels per well. Our type curve is 456,000 barrels equivalent, and so we're still in that range. We have 380 wells planned for 2012, and the industry to date, combining what we drill and with other companies, there's been about 500 wells, horizontal wells drilled, in this play. The key to this whole play is the ability to move water inexpensively, and I think we are the leader as far as going out and spending money and designing our infrastructure for water disposal. And so you have high oil prices, you have cheap water disposal, that drives a very high rate of return for the Mississippian.

Mississippian production growth has been just as remarkable as the play. We started out in January 2010 with very, very little production for the Miss. In fact, we drilled and completed our first well in late 2009. We averaged 5 rigs in 2010, we averaged 15 rigs in the play in 2011, and we're moving up to 26 rigs, average, in 2012. And so production has gone from nearly nothing in January 2010 to over 21,000 barrels of oil equivalent per day today.

Mississippian economics are very robust. You're looking at 456,000 barrels of oil equivalent, $3.2 million per well. That includes saltwater disposal infrastructure, IP at 375 barrels of oil equivalent per day. The PV-10 on each well is roughly $5.5 million and a 91% rate of return.

So in 2012, we're looking at 380 wells, and net of our JVs, we're looking at about a 62% working interest at the play. As I mentioned, 7,000 locations, that's based on 3 wells per section, so there could be upside to that if we decide to go to 4 wells per section. And you can see the economic is in a type curve even at $60 oil, which is the bulk of the economics in this play is oil. Even at $6 oil, you're at about 40% rate of return, and that the strip today is somewhere north of 90%.

The Permian Basin, the Central Basin Platform, that remains to be a very, very important and core area for SandRidge. We -- again, it's a shallow carbonate drilling that we do there. Most of our drilling in 2012 will be less than 5,000 feet deep in the San Andres formation. About 600 locations of the 759 locations, we plan to drill in 2012 to be San Andres wells. So we have about 225,000 acres on the Central Basin Platform, and we're the most active driller with 13 rigs running. And it does have an NAV value of $7.2 billion. There are multiple play objectives in the Central Basin Platform from the Grayburg/San Andres to the Clear Fork to the Penn., but the bulk of the drilling is in the San Andres play. And today, we are the fifth most active operator on the platform in terms of well count. And you see we're in league with some -- with a pretty good company there. The Central Basin Platform, we have 6 of the major producing fields on the platform, and that has been a very, very good area for SandRidge as far as growing oil production.

The Permian. We look at the Permian as a area of steady growth. Of course, we have some tremendous growth when we acquired Forest and we acquired Arena, but since -- again, since about July 2010, we've grown production from about 25,000 barrels equivalent to about 32,000 barrels equivalent. One of the things we talked about in the Permian Basin was some infrastructure work back in our November call, and these were 28 pressure reduction projects that we're working on. We completed 11 of those before the end of the year. We should complete about another dozen here by the end of this quarter and finish out that project by the end of the second quarter. So everything's going as well as planned there, and we should continue to see production ramping up as we drill.

Permian economics remain very robust. Again, these are low cost vertical wells, all 759 wells we have planned in 2012 are vertical wells. About $643,000 per well, finding about 53 -- I'm sorry, 58,000 barrels of oil equivalent, but with most of that is crude oil. PV-10 per well, you're looking at just slightly under $0.75 million and very high working interest. On average, we're looking at 91% working interest.

If you look at the economics on the Permian at $60 oil, you're looking about 20% rate of return. So we do have a lot of room there on oil price. And at the Strip, we're at roughly, I don't know, 70%, 72% rate of return.

The capital plan for 2012. In the Mid-Continent, before the carried interest from Repsol and from Atinum, the Mid-Continent really, we're going to spend about $900 million, and that includes drilling the horizontal producers, and also, the saltwater disposal system. So that is probably 60% of the total E&P budget. The Permian Basin, we're looking at drilling -- spending about $0.5 billion there. And then offshore, $200 million and then all other areas as you see very little.

So you have a total E&P cost of $1.6 billion. That's before workovers and capitalized G&A, but we do have about $300 million worth of drilling period this year with Repsol and with Atinum, so that would reduce the net impact on the Mid-Continent drilling, would be reduced from $755 million to about $455 million. So when you add back in workovers and G&A, our total E&P budget is $1.55 billion. As you remember, the carry on the drilling total combined with the 2 JVs is right at $1 billion, and we look for that carry to run out in about 3 years. So it is a very aggressive carry program.


We gave you the breakout by oil and gas. I won't go through that in detail, just for your information purposes.

And then finally, we give you a pro forma with Sandridge and with Dynamic. And keep in mind, it still includes the Royalty Trust, so we haven't pro forma-ed it out the third-party interest in the royalty trust. But we did give you the increases, 28% up improvement value, proved develop actually goes up from 56% to 64%. And then finally, you will see, instead of us being 26 and -- I mean a higher percent in Mid-Continent and Permian, the Gulf of Mexico does come up from 1% to 22% of our portfolio on a proven basis.

With that, I think I will turn it over to James.

James D. Bennett

Thanks, Rodney. I will wrap up with the financial overview and then we'll take some Q&As. So in terms of the finance section, it's really the oil assets of the companies put together over the last few years really set us up for what we're able to do in '11.

We were able to monetize all the significant amount of assets that we put together over the last few years in terms of with the Permian acquisitions, with the acreage acquisitions in the Mississippi and really set us up to accomplish what we did in '11. And that put us in a position where we're in a stronger position, credit profile wise. We're able to pay down debt. And the Dynamic acquisition, which I'll get into, was really part of that 3-year strategy.

In terms of what we accomplished in '11, we're able to raise about $2 billion of capital. Starting off with $400 million in cash flow from operations and $1.8 billion capital budget, we think that was a pretty lofty goal, but we accomplished it. We did that through 2 royalty trusts. We're the first public company to execute a royalty trust. We raised $900 million through the trusts. We sold $600 million through asset sales of the noncore assets and then $500 million upfront cash proceeds from 2 joint ventures, both in the Mississippi.

At the same time, we took our leverage down from 4.5x to 4x and then pro forma Dynamic further down at 3.3x. We ended the year with $1 billion of liquidity, nothing drawn on our $800 million credit facility and $200 million of cash. And then we capped the year with 4 quarters of sequential quarter-over-quarter EBITDA growth. First quarter was $148 million. In the fourth quarter, we ended with $175 million. So feel good about what we accomplished in '11, and this is, as Tom said, it was really a year of transformation for us in monetizing the assets and setting us up to do the things that we were able to do last year.

Objectives for '12. Fully funded $1.85 billion capital program. That will be funded with -- we ended the year again with cash on our balance sheet of about $200 million. I'll go through a waterfall chart here, but we -- proceeds from the Repsol joint venture, some proceeds from some royalty trust units we sold week. That combined with our pending royalty trust and a fully undrawn revolver easily funds us for '12. So we have '12 fully funded. We will complete that deal, the pending trust, we can't talk about it in great detail because it's still under registration. We do expect to realize proceeds for that early in the second quarter of about $500 million.

Close Dynamic, that will happen also in April. We'll receive the Dynamic audit about late March and we'll close about 30 days after that. We'll also here in the next month or 2 be entering into a new credit facility. Our facility doesn't mature until 2014, but we thought it's prudent to go ahead and extend that, probably extend it out 5 years, and we think we'll take the borrowing base from $790 million now to right around the $1 billion range. Again, that will close some time in April as well.

And we'll continue to hedge this year. As you know over the last several years, we've been an active hedger in terms of the oil market. If we can lock in these kind of returns in $100 oil, we think it's very prudent to do that. As long as we're not seeing service cost increase and protects our balance sheet, and we think it's one of the risks that we have in this business being price takers is commodity prices, so if we can hedge that risk and take it off the table, we're going to continue to do that and you'd seen this hedge out into '14.

In terms of the Dynamic acquisition, Tom talked about the 6 different things we could have done to bridge our funding gap and really get us to our 3-year plan, everything from selling acreage, taking on more debt, issuing common equity, doing more royalty trust. This to us was the most accretive way to get there and de-risk the company the best way. It's accretive on all -- from a cash flow and earnings measures. And some people have asked how is it accretive on an NAV and NAV can be a tricky thing. But one way to think about it is had we not done something like this, we probably would have sold or joint ventured maybe up to 0.5 million acres in the Miss. And if you look at Rodney's NAV model, the $23 billion, 1.5 million acres, it's about $15 -- I'm sorry, $15,000 an acre. So $0.5 billion, 500,000 acres, a little over $7 million, $7 billion of NAV. So by us doing Dynamic, we don't have to sell 0.5 million of acres in the Miss. We can keep 250,000 of those only sell 250,000. So for us, we think of it as NAV accretive and earnings and cash flow accretive. At the same time, deleverage us, takes our leverage from over 4x to about 3.3x and still maintain strong liquidity. We still have $1 billion liquidity right now.

Capitalization. In terms of where we've come the last 4 quarters, we ended the year with $2.9 billion of net debt. December 31, right now, we're at $2.6 billion of debt. Again, that was because of successful capital raising we had last year. We took our leverage from 4.5x down to 4x. Pro forma Dynamic further takes it down to 3.3x. Another measure we look at a lot, debt to production, $47,000 per flowing barrel down to $40,000, then down to $37,000 again with the Dynamic acquisition. So again, de-risk the business and puts us in a better position balance sheet wise.

In terms of our capital structure, a very solid capital structure. Only $350 million of maturities over the next 4 years. Those are the floaters due in 2014. Those are called on that 101 on April on par. $765 million of converts. We start to be able to mandatorily convert those in 2014. And our long bond right now, the $900 million is trading right at par at about 7.5%. So I feel very good about our capital structure and our lack of near-term maturities. And as you remember earlier, in '11, we refinanced our 2015 bonds and pushed that maturity out to 2021.

In terms of our credit facility, it's $790 million borrowing base right now. This is the one we anticipate amending and extending probably in April. Pushed it out 5 years and increased the borrowing base to right around $1 billion. So we have a group of 25 banks and Bank of America is the lead on this.

Our measures over the last few years, so what we've been able to do with and without Dynamic, we've grown our oil production. You can see up to the top right, and it's really this transition of oil that set the company up where it is now. So on the left, our EBITDA has been relatively flat. A lot of that is due to high gas hedges that we had in 2009 and 2010. Those hedges are rolling off. We've made the transition to oil. Oil comprises more than 50% of our production now and, as Tom said, about 80% of our revenues.

And on the bottom right, you see our debt measures continue to improve those. One of the goals we did lay out last year was to improve our credit profile. We didn't think being 4.5x levered was prudent and we've done that over the last year through the combination of the capital raises that I'll go over on this page and the Dynamic acquisition.

So this is what we laid out on the top of the page in '11 that we wanted to accomplish. So an EBITDA goal of about $700 million, these are actual numbers we showed you guys last year. Cash flow of a little over $400 million and $1.8 billion capital plan.

So we were able to fully fund the last years with the transactions we did. And what that confidence in our capital raising was we saw we had success with the royalty trust, we were able to do another Permian Trust. That really allowed us to increase our drilling plan. In August, we announced that. That allowed us to start drilling up in the Kansas and really see the extension Miss. So had we not had the success in capital raising, had we not gone out and increase our CapEx budget in August and acquired the additional Mississippian extension, we wouldn't be in the position we're in today.

So again, 2011 is really a transformative year in terms of setting us up to accomplish what we did. And in '12, similarly, we're in a much better position, still have a funding gap. But as you can see with the year-end cash, Repsol cash and unit sales, our pending trust, we've basically got the '12 gap fully funded. Well, we may have very small draw under our $1 billion revolver, but we're fully funded for '12.

In terms of our hedges. As we said earlier, we're an active hedger. We'll continue to hedge. We have about 82% of our combined production with Dynamic hedged, just over $99 in terms of swap and a small amount of collars as well. The small amount of gas hedges and collars. We're hedging out into '14 now. Again for us, if we can lock in either between 70% and 90% return to these prices, we think it's prudent to do that and you'll see us continue to hedge.

Joint venture. These 2 summary pages on Atinum and the Repsol joint ventures. You guys have seen this before, but we put a summary in here for you. And this was one that was -- the Atinum was announced in August and closed in September, $500 million, 50% cash upfront, 50% in the form of carrying. This value at the Miss at about $4,400 an acre based on 113,000 acres.

And in the second, Repsol announced in December, closed in January, $1 billion, $250 million cash upfront, $750 million carried. We think we'll use over 3 years as well in that value. That was 114,000 acres in the Original Miss and 250,000 extension valued at about $2,750 an acre.

That's actually the end of our prepared remarks. There's a guidance section in the back. It's identical to the guidance that we put out in our earnings release last week. I'll just note a couple things on that. As Kevin said, that assumes closing of Dynamic on April 30. So SandRidge standalone for the first quarter through end of April, the contribution Dynamic May 1 there forward. As you're looking at -- although we don't give our quarterly guidance, as you're looking at the first quarter, I would point you towards the guidance that we have in our last 2 presentations, Goldman and Crédit Suisse, to look at SandRidge on a standalone basis before the impact of Dynamic.

And with that, I think we'll have Tom and Matt come up and open it up to questions.

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