EX-99.1

EX-99.1 2 d685134dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

LOGO

SandRidge Energy, Inc. Updates Shareholders on Operations and Reports Financial Results for Fourth Quarter and Full Year 2013

Exceeded 2013 Production Guidance with Lower than Projected Capital Expenditures

- Produced 33.8 MMBoe, 1% more than guidance of 33.6 MMBoe

- Spent $1.424 Billion, 2% less than guidance of $1.450 Billion

Increased Mid-Continent Production 8% to 51.7 MBoe per Day from the Previous Quarter, 44% Above the Fourth Quarter of 2012

Delivered 80 Mid-Continent Wells with an Average 30-day IP of 386 Boe per Day during the Fourth Quarter; 2013 Average 30-day IP was 366 Boe per Day

Successful Appraisal Program Adds Sumner County, Kansas to the Focus Area

Increased PUD Type Curve: Oil EUR Up 10% and Boe EUR Up 3%

434% Reserve Replacement and All-in Finding and Development Cost of $11.72 per Boe, Based on Retained Properties

Oklahoma City, Oklahoma, February 27, 2014 – SandRidge Energy, Inc. (NYSE: SD) today announced financial and operational results for the quarter and year ended December 31, 2013. Additionally, presentation slides will be available on the company’s website, www.sandridgeenergy.com, under Investor Relations/Events at 7am EST on February 28.

James Bennett, SandRidge’s Chief Executive Officer and President, commented, “I’m pleased to report our changes at SandRidge are yielding strong economic results for our shareholders. We’re executing our numbers, having new successes, and the teams are working on innovations to dramatically improve already strong returns. With our advantaged infrastructure and focus, we can economically do what others can’t in the Mid-Continent, where multi-zone horizontal drilling is still a new approach in this oily basin.

“We are already producing from six oil rich zones in the Mid-Continent focus area. Consistent execution and continued improvements have increased our Mississippian type curve EUR by 3% over 2012, while reserve replacement was 434%. As an example of appraisal success, we’ve now added Sumner County, Kansas, where we have over 100,000 acres, to our focus area. We look forward to giving more detail on all of this, introducing our three year production outlook as well as discussing our ideas to unlock the value of our water disposal business, at our New York City analyst day March 4.”

Key Financial Results

Fourth Quarter

•

Pro forma for divestitures and net of Noncontrolling Interest, adjusted EBITDA was $166 million in the fourth quarter of 2013 compared to $130 million in the fourth quarter of 2012. Adjusted EBITDA, net of Noncontrolling Interest, was $229 million for fourth quarter 2013 compared to $318 million in fourth quarter 2012.

•

Adjusted operating cash flow of $218 million for fourth quarter 2013 compared to $259 million in fourth quarter 2012.

•

Adjusted net income of $14.9 million, or $0.03 per diluted share, for fourth quarter 2013 compared to adjusted net income of $35.3 million, or $0.06 per diluted share, in fourth quarter 2012.

Full Year

•

Pro forma for divestitures and net of Noncontrolling Interest, adjusted EBITDA was $609 million for 2013 compared to $365 million for 2012. Adjusted EBITDA, net of Noncontrolling Interest, was $1,020 million for 2013 compared to $1,070 million in 2012.

•

Adjusted operating cash flow of $812 million for 2013 compared to $915 million in 2012.

•

Adjusted net income of $103.9 million, or $0.18 per diluted share, for 2013 compared to adjusted net income of $124.3 million, or $0.23 per diluted share, in 2012.

Adjusted net income available to common stockholders, adjusted EBITDA, pro forma adjusted EBITDA and operating cash flow are non-GAAP financial measures. Each measure is defined and reconciled to the most directly comparable GAAP measure under “Non-GAAP Financial Measures” beginning on page 11.

Highlights

David Lawler, SandRidge’s Chief Operating Officer, commented, “Our Mid-Continent business units delivered another exceptional quarter. In addition to bringing 80 horizontal wells online for a record average low of $2.9 million each, we achieved our lowest Mid-Continent operating cost to date at $6.91 per Boe. The reduction in capital expenditures is linked primarily to redesigned well site facilities and synchronized pad drilling. Beyond these leading metrics, our appraisal program expanded our focus area to Sumner County, Kansas. Five wells drilled in the area produced an average 30-day IP of 601 Boe per day, or 90% above year-end 2013 Type Curve. The new development area consists of 117,000 net acres, and we plan to drill 45 wells there in 2014. The Chester horizontal program continued to exceed expectations with two additional wells delivering an average 30-day IP of 726 Boe per day at 85% oil. SandRidge is the first mover of horizontal Chester development targeting oil, and we plan to rapidly accelerate this program in 2014. By the end of the second quarter, we anticipate 12 additional wells will be online. Furthermore, our second tranche of Woodford test wells showed a marked improvement over the first tranche. Of the two new wells, one delivered a 30-day IP of 96 Boe per day at 67% oil, and the second delivered a 30-day IP of 190 Boe per day at 85% oil.”

Fourth Quarter Operational Highlights

•

Added new focus area in Sumner County, Kansas

•

Five appraisal wells in the area delivered 601 Boe per day 30-day IPs, ~2x type curve

•

Added 117,000 acres to focus area through appraisal drilling success

•

Notable 30-day IP results during the fourth quarter

•

Three wells greater than 1,000 Boe per day with an average of 1,401 Boe per day

•

Two Chester wells averaged 726 Boe per day (85% oil)

•

80 Mid-Continent wells averaged 386 Boe per day

•

Two new Woodford wells: Enhanced understanding yields improving results

•

First well had a 30-day IP of 96 Boe per day (67% oil)

•

Second well had a 30-day IP of 190 Boe per day (85% oil)

•

Reduced fourth quarter average Mid-Continent well cost to $2.9 million

•

Reduced fourth quarter Mid-Continent LOE to $6.91 per Boe

Full Year Operational Highlights

•

2013 year-end reserve metrics (based on retained properties only which excludes divested Gulf of Mexico and Permian properties)

•

10% increase in Mississippian PUD type curve oil EUR to 118 Mbo and 3% increase in overall EUR to 380 MBoe

•

Added 117 MMBoe through the drillbit with 520% drillbit reserve replacement

•

434% reserve replacement overall with all-in F&D of $11.72 per Boe

•

41% increase in consolidated SEC PV-10 reserves value to $4.1 billion

•

25% increase in consolidated proved reserves to 377 MMBoe

•

29% increase in consolidated proved liquids reserves of 173 MMBbls

•

63% of total reserves are proved developed reserves, 68% of value is proved developed

•

Proved reserves/production ratio of 16.7 years

•

Notable 30-day IP results during 2013

•

17 wells greater than 1,000 Boe per day with an average of 1,342 Boe per day

•

Reduced average full-year Mid-Continent well cost by 11% to $3.1 million

•

Reduced full-year Mid-Continent LOE by 14% to $7.53 per Boe

•

Producer to disposal well ratio improved from 7x in 2012 to 16x in 2013. Additionally, SWD capex as a percent of Mid-Continent capex decreased from 24% to 12% year-over-year.

•

Drilled 28 disposal wells in 2013 and exited the year disposing approximately 935,000 gross barrels of water per day

Financial / Other Highlights

•

Pro forma Adjusted EBITDA grew 67% year-over-year to $609 million

•

Closed sale of Gulf of Mexico business on February 25, 2014 for $750 million, subject to customary adjustments

•

Pro forma for the Gulf of Mexico sale, year-end liquidity of $2.3 billion ($1.55 billion of cash) and a 2.7x leverage ratio

•

94% of liquids production hedged and 65% of natural gas production hedged in 2014

Drilling and Operational Activities

Mid-Continent. During the fourth quarter of 2013, SandRidge drilled 94 horizontal wells: 66 in Oklahoma and 28 in Kansas. SandRidge also drilled eight disposal wells during the quarter. The company averaged 22 horizontal rigs operating in the play: 17 in Oklahoma and five in Kansas. Additionally, the company averaged one rig drilling disposal wells. The company’s Mid-Continent assets produced 51.7 MBoe per day during the fourth quarter (49% liquids).

Gulf of Mexico / Gulf Coast. The company’s Gulf of Mexico and Gulf Coast assets produced 23 MBoe per day during the fourth quarter of 2013 (53% liquids).

Permian Basin. In the company’s Permian properties, 49 wells were drilled during the fourth quarter of 2013, all for SandRidge Permian Trust. The company’s Permian Basin assets produced 6.2 MBoe per day during the quarter (96% liquids).

Other Operating Areas. During the fourth quarter, SandRidge’s legacy West Texas properties produced approximately 6.3 MBoe per day (99% natural gas). Additionally, its legacy Mid-Continent assets produced 1.9 MBoe per day in the quarter (79% natural gas).

Royalty Trusts. At December 31, 2013, the company was obligated to drill 22 development wells for SandRidge Mississippian Trust II (“SDR”) and 205 development wells for SandRidge Permian Trust (“PER”). The company expects to complete its drilling obligation for SDR in the second quarter of 2014 and for PER in the fourth quarter of 2014. The company completed its drilling obligation to SandRidge Mississippian Trust I (“SDT”) in the second quarter of 2013.

Analysis of Changes in Consolidated Proved Reserves

While producing 34 million barrels of oil equivalent (MMBoe) in 2013 (including 11.2 MMBoe of production associated with divested assets in the Gulf of Mexico, Gulf Coast, and Permian Basin), SandRidge added 119 MMBoe to proved reserves during 2013 from discoveries and extensions. Horizontal drilling in the Mississippian play contributed 107 MMBoe of the additions.

The company’s overall reserve additions were 100 MMBoe, after taking into account positive pricing revisions of 17 MMBoe and negative revisions of previous estimates of 36 MMBoe. The negative revisions are primarily linked to the company’s ongoing efforts to high grade its drilling plan. Numerous additional high quality drilling locations replaced certain former PUD locations in the company’s five year drilling plan and resulted in an improved type curve. Because the company no longer anticipates drilling these locations within five years, it removed them from the PUD classification, resulting in a majority of the negative revisions. The company’s PUD type curve includes a 10% improved oil EUR to 118 MBo and, overall, a 3% increase to 380 MBoe.

Considering only those assets retained by the company after the Gulf sale, the company achieved reserve replacement of 434%, primarily due to continued successful execution of horizontal drilling programs in the Mississippian play. SandRidge’s all-in finding and development cost for retained assets was $11.72 per barrel of oil equivalent.

SEC Reserves and Value


	Oil (MBbls)			NGL (MBbls)			Liquids (MBbls)			Gas (MMcf)			Net Resv (MBoe)⁽¹⁾			PV-10 (in thousands)⁽²⁾
Year End 2012 ($91.21 / $2.76)		262,045			67,994			330,039			1,415,042			565,880		$	7,488,444
Sales		(131,769	)		(29,067	)		(160,836	)		(228,229	)		(198,874	)
Acquisitions		43			13			56			363			117
Production		(14,279	)		(2,291	)		(16,570	)		(103,233	)		(33,776	)
Extensions		40,570			18,686			59,256			359,918			119,242
Revisions - Performance		(12,560	)		15			(12,545	)		(141,156	)		(36,071	)
Revisions - Pricing / Differentials		(1,409	)		3,702			2,293			87,724			16,913

Year End 2013 ($93.42 / $3.67)		142,641			59,052			201,693			1,390,429			433,431		$	5,191,635

Southern Division Sale Adjustments		(26,332	)		(2,569	)		(28,901	)		(167,375	)		(56,797	)		(1,088,872	)

Pro Forma Year End 2013		116,309			56,483			172,792			1,223,054			376,634		$	4,102,763

Pro Forma Year End 2013: Proved Developed as a percent of Total Proved		56	%		60	%		57	%		69	%		63	%		68	%

⁽¹⁾	Includes approximately 29,922 MBoe and 38,230 MBoe attributable to noncontrolling interests at December 31, 2013 and 2012, respectively.

⁽²⁾	Includes PV-10 attributable to noncontrolling interests of approximately $783 million and $955 million at December 31, 2013 and 2012, respectively.

Standardized Measure of Discounted Net Cash Flows to PV-10 Reconciliation


	Year End
			Sale			Pro Forma
	2013		Adjustment			2013		2012
	(in millions)
Standardized measure of discounted net cash flows ⁽¹⁾⁽²⁾	$	4,018	$	(843	)	$	3,175	$	5,840
Present value of future net income tax expense discounted at 10%		1,174		(246	)		928		1,648

PV-10 ⁽³⁾	$	5,192	$	(1,089	)	$	4,103	$	7,488

⁽¹⁾	Includes approximately $782 million and $953 million attributable to SandRidge noncontrolling interests at December 31, 2013 and 2012, respectively.

⁽²⁾	Sale adjustment represents an allocation of the Company’s Standardized Measure to the sale properties based on PV-10 attributable to sale properties relative to the Company’s total PV-10.

⁽³⁾	Includes approximately $783 million and $955 million attributable to SandRidge noncontrolling interests at December 31, 2013 and 2012, respectively.

Operational and Financial Statistics

Information regarding the company’s production, pricing, costs and earnings is presented below:


	Three Months Ended December 31,					Year Ended December 31,
	2013		2012			2013			2012
Production
Oil (MBbl)		3,377		4,451			14,279			15,868
NGL (MBbl)		683		586			2,291			2,094
Natural gas (MMcf)		24,891		28,717			103,233			93,549
Oil equivalent (MBoe)		8,209		9,823			33,776			33,553
Daily production (MBoed)		89.2		106.8			92.5			91.7

Average price per unit
Oil price per barrel—as reported	$	94.96	$	88.15		$	97.58		$	91.79
Impact of derivatives per barrel		2.12		10.63			1.32			5.74

Net price per barrel	$	97.08	$	98.78		$	98.90		$	97.53


NGL price per barrel—as reported	$	36.74	$	31.96		$	35.16		$	33.10
Impact of derivatives per barrel		—		—			—			—

Net price per barrel	$	36.74	$	31.96		$	35.16		$	33.10


Natural gas price per Mcf—as reported	$	3.33	$	3.09		$	3.36		$	2.49
Impact of derivatives per Mcf		0.23		(0.30	)		0.10			(0.03	)

Net price per Mcf	$	3.56	$	2.79		$	3.46		$	2.46


Price per Boe—as reported	$	49.17	$	50.89		$	53.89		$	52.43

Net price per Boe—including impact of derivatives	$	50.73	$	59.96		$	54.79		$	55.04


Average cost per Boe
Lease operating ⁽¹⁾	$	18.37	$	13.67		$	15.29		$	14.22
Production taxes		0.91		1.12			0.96			1.41
General and administrative
General and administrative, excluding stock-based compensation	$	3.87	$	7.45		$	7.26		$	5.93
Stock-based compensation		0.73		0.98			2.52			1.28

Total general and administrative	$	4.60	$	8.43		$	9.78		$	7.21
General and administrative—adjusted
General and administrative, excluding stock-based compensation ⁽²⁾	$	3.49	$	4.62		$	4.14		$	4.64
Stock-based compensation ⁽³⁾		0.63		0.98			0.88			1.28

Total general and administrative—adjusted	$	4.12	$	5.60		$	5.02		$	5.92

Depletion ⁽⁴⁾	$	17.35	$	18.83		$	17.90		$	17.79

Lease operating cost per Boe
Mid-Continent	$	6.91	$	7.55		$	7.53		$	8.75
Offshore		30.27		19.71			24.60		$	21.77

Earnings per share
Earnings (loss) per share applicable to common stockholders
Basic	$	0.01	$	(0.63	)	$	(1.27	)	$	0.19
Diluted		0.01		(0.63	)		(1.27	)		0.19

Adjusted net income per share available to common stockholders
Basic	$	0.00	$	0.04		$	0.10		$	0.15
Diluted		0.03		0.06			0.18			0.23

Weighted average number of common shares outstanding (in thousands)
Basic		483,936		476,241			481,148			453,595
Diluted ⁽⁵⁾		574,832		566,664			571,801			546,148

⁽¹⁾	Includes shortfall penalties related to CO₂ delivery requirement.

⁽²⁾

Excludes transaction costs, legal settlements, severance, annual incentive plan adoption effect and consent solicitation costs totaling $3.2 million and $105.4 million for the three-month period and year ended December 31, 2013, respectively. Excludes transaction costs, legal settlements and consent solicitation costs totaling $27.8 million and $43.1 million for the three-month period and year ended December 31, 2012, respectively.

⁽³⁾	Three-month period and year ended December 31, 2013 exclude $0.8 million and $55.5 million, respectively, for the acceleration of certain stock awards.

⁽⁴⁾	Includes accretion of asset retirement obligation.

⁽⁵⁾	Includes shares considered antidilutive for calculating earnings per share in accordance with GAAP for certain periods presented.

Discussion of 2013 Financial Results

Fourth Quarter

Oil and natural gas revenue decreased 14% to $429 million in the fourth quarter of 2013 from $500 million in the same period of 2012 primarily as a result of a 16% decrease in total production due to the Permian divestiture that closed during the first quarter of 2013. Reported prices, which exclude the impact of derivative settlements, were $94.96 per barrel of oil and $3.33 per Mcf of natural gas during the fourth quarter of 2013 compared to $88.15 per barrel and $3.09 per Mcf in the same period of 2012.

During the fourth quarter of 2013, production expense was $18.37 per Boe compared to $13.67 per Boe in the fourth quarter of 2012. The increase was primarily due to an accrual of 2013 shortfall penalties related to the Company’s CO₂ delivery requirement in the WTO. In SandRidge’s Mid-Continent operations, fourth quarter production expense decreased 8% year-over-year to $6.91 from $7.55 per Boe as a result of continued efficiency improvements.

Full Year

Oil and natural gas revenue increased 3% to $1,820 million in 2013 from $1,759 million in 2012 as a result of increases in average prices received for oil and natural gas production. Realized reported prices increased to $97.58 per barrel of oil and $3.36 per Mcf during 2013 compared to $91.79 per barrel and $2.49 per Mcf in 2012. Total 2013 production was consistent with 2012. The table below presents 2013 and 2012 production by area.


	2013				2012
	(MBoe)				(MBoe)
Mid-Continent		17,027	50	%		10,149	30	%
Gulf of Mexico/Gulf Coast		10,082	30	%		8,110	24	%
Permian Basin		3,366	10	%		10,963	33	%
Other		3,301	10	%		4,331	13	%

		33,776	100	%		33,553	100	%

Production expense for 2013 was $15.29 per Boe compared to 2012 production expense of $14.22 per Boe due primarily to WTO CO₂ shortfall delivery penalties. In the company’s Mid-Continent operations, 2013 production expense decreased 14% year-over-year to $7.53 from $8.75 per Boe.

Capital Expenditures

The table below summarizes the company’s capital expenditures for the three-month period and year ended December 31, 2013 and 2012:


	Three Months Ended December 31,						Year Ended December 31,
	2013			2012			2013			2012
	(in thousands)
Drilling and production
Mid-Continent	$	197,145		$	251,108		$	844,167		$	927,186
Permian Basin		36,574			120,667			192,477			645,045
Gulf of Mexico/Gulf Coast		30,968			65,081			192,668			169,458
WTO/Tertiary/Other		—			1,621			—			22,370

		264,687			438,477			1,229,312			1,764,059
Leasehold and seismic
Mid-Continent		48,263			10,024			100,874			156,961
Permian Basin		493			2,555			14			15,463
Gulf of Mexico/Gulf Coast		2,377			3,205			4,449			16,097
WTO/Tertiary/Other		1,375			24			5,686			2,307

		52,508			15,808			111,023			190,828
Inventory		(7,563	)		4,060			(21,947	)		(3,941	)
Total exploration and development		309,632			458,345			1,318,388			1,950,946

Drilling and oil field services		2,468			302			7,125			27,527
Midstream		8,823			18,454			55,706			80,413
Other - general		4,505			23,688			42,664			115,096

Total capital expenditures, excluding acquisitions		325,428			500,789			1,423,883			2,173,982

Acquisitions		1,501			(13,758	)		17,028			840,740

Total capital expenditures	$	326,929		$	487,031		$	1,440,911		$	3,014,722

Plugging and abandonment	$	26,066		$	19,728		$	133,626		$	84,361

Derivative Contracts

The table below sets forth the company’s consolidated oil and natural gas price swaps and collars for the years 2014 and 2015 as of February 25, 2014 and include contracts that have been novated to or the benefits of which have been conveyed to SandRidge sponsored royalty trusts.


	Quarter Ending
	3/31/2014		6/30/2014		9/30/2014		12/31/2014
Oil (MMBbls):
Swap Volume		1.36		0.74		1.01		1.19
Swap	$	95.85	$	100.56	$	99.41	$	98.80
Three-way Collar Volume		1.96		1.93		2.07		2.07
Call Price	$	100.00	$	100.00	$	100.00	$	100.00
Put Price	$	90.21	$	90.22	$	90.20	$	90.20
Short Put Price	$	70.00	$	70.00	$	70.00	$	70.00
Natural Gas (Bcf):
Swap Volume		14.68		13.65		13.80		11.04
Swap	$	4.23	$	4.25	$	4.25	$	4.31
Collar Volume		0.23		0.23		0.24		0.24
Collar: High	$	7.78	$	7.78	$	7.78	$	7.78
Collar: Low	$	4.00	$	4.00	$	4.00	$	4.00


	Year Ending
	12/31/2014		12/31/2015
Oil (MMBbls):
Swap Volume		4.29		5.31
Swap	$	98.31	$	92.55
Three-way Collar Volume		8.03		2.92
Call Price	$	100.00	$	103.13
Put Price	$	90.21	$	90.82
Short Put Price	$	70.00	$	73.13
Natural Gas (Bcf):
Swap Volume		53.17		15.40
Swap	$	4.26	$	4.50
Collar Volume		0.94		1.01
Collar: High	$	7.78	$	8.55
Collar: Low	$	4.00	$	4.00

Balance Sheet

The company’s capital structure at December 31, 2013 and December 31, 2012 is presented below (in thousands):


	December 31,			December 31,
	2013			2012
	(in thousands)
Cash and cash equivalents	$	814,663		$	309,766

Current maturities of long-term debt	$	—		$	—
Long-term debt (net of current maturities)
Senior credit facility		—			—
Senior Notes
9.875% Senior Notes due 2016, net		—			356,657
8.0% Senior Notes due 2018		—			750,000
8.75% Senior Notes due 2020, net		444,736			444,127
7.5% Senior Notes due 2021		1,178,922			1,179,328
8.125% Senior Notes due 2022		750,000			750,000
7.5% Senior Notes due 2023, net		821,249			820,971

Total debt		3,194,907			4,301,083
Stockholders’ equity
Preferred stock		8			8
Common stock		483			476
Additional paid-in capital		5,294,551			5,228,019
Treasury stock, at cost		(8,770	)		(8,602	)
Accumulated deficit		(3,460,462	)		(2,851,048	)

Total SandRidge Energy, Inc. stockholders’ equity		1,825,810			2,368,853

Noncontrolling interest		1,349,817			1,493,602
Total capitalization	$	6,370,534		$	8,163,538

During the fourth quarter of 2013, the company’s debt, net of cash balances, increased by approximately $105 million as a result of funding the company’s drilling program. On February 25, 2014, the company had no amount drawn under its $775 million senior credit facility and, due to the closing of the Gulf of Mexico sale, approximately $1.35 billion of cash, leaving approximately $2.1 billion of available liquidity. The company was in compliance with all applicable covenants contained in its debt agreements during 2013 and through and as of the date of this release.

2014 Operational Guidance: The company is updating its 2014 guidance to include adjusted EBITDA attributable to noncontrolling interest.


	Projection as of	Projection as of
	January 7, 2014	February 27, 2014
Production
Oil (MMBbls)	11.9	11.9
Natural Gas Liquids (MMBbls)	3.6	3.6

Total Liquids (MMBbls)	15.5	15.5
Natural Gas (Bcf)	83.0	83.0

Total (MMBoe)	29.3	29.3
Price Realization
Oil (differential below NYMEX WTI)	$2.50	$2.50
Natural Gas Liquids (realized % of NYMEX WTI)	33%	33%
Natural Gas (differential below NYMEX Henry Hub)	$1.00	$1.00
Costs per Boe
Lifting	$11.15 - $13.15	$11.15 - $13.15
Production Taxes	1.15 - 1.35	1.15 - 1.35
DD&A - oil & gas	15.60 - 17.60	15.60 - 17.60
DD&A - other	2.20 - 2.40	2.20 - 2.40

Total DD&A	$17.80 - $20.00	$17.80 - $20.00
G&A - cash	3.60 - 4.00	3.60 - 4.00
G&A - stock	0.65 - 0.80	0.65 - 0.80

Total G&A	$4.25 - $4.80	$4.25 - $4.80
EBITDA from Oilfield Services, Midstream and Other ($ in millions)⁽¹⁾	$20	$20
Adjusted Net Income Attributable to Noncontrolling Interest ($ in millions)⁽²⁾	$120	$120
*Adjusted EBITDA Attributable to Noncontrolling Interest ($ in millions)⁽³⁾*		*$155*
Corporate Tax Rate	0%	0%
Deferral Rate	0%	0%
Capital Expenditures ($ in millions)
Exploration and Production	$1,230	$1,230
Land and Seismic	120	120

Total Exploration and Production	$1,350	$1,350
Oil Field Services	15	15
Midstream and Other	110	110

Total Capital Expenditures (excluding acquisitions)	$1,475	$1,475

⁽¹⁾

EBITDA from Oilfield Services, Midstream and Other is a non-GAAP financial measure as it excludes from net income interest expense, income tax expense and depreciation, depletion and amortization. The most directly comparable GAAP measure for EBITDA from Oilfield Services, Midstream and Other is Net Income from Oilfield Services, Midstream and Other. Information to reconcile this non-GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods and/or does not forecast the excluded items on a segment basis.

⁽²⁾

Adjusted Net Income Attributable to Noncontrolling Interest is a non-GAAP financial measure as it excludes gain or loss due to changes in fair value of derivative contracts and gain or loss on sale of assets. The most directly comparable GAAP measure for Adjusted Net Income Attributable to Noncontrolling Interest is Net Income Attributable to Noncontrolling Interest. Information to reconcile this non-GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods.

⁽³⁾

Adjusted EBITDA Attributable to Noncontrolling Interest is a non-GAAP financial measure as it excludes from net income interest expense, income tax expense, depreciation, depletion and amortization, gain or loss due to changes in fair value of derivative contracts and gain or loss on sale of assets. The most directly comparable GAAP measure for Adjusted EBITDA Attributable to Noncontrolling Interest is Net Income Attributable to Noncontrolling Interest. Information to reconcile this non-GAAP financial measure to the most directly comparable GAAP financial measure is not available at this time, as management is unable to forecast the excluded items for future periods.

Non-GAAP Financial Measures

Adjusted operating cash flow, adjusted EBITDA, pro forma adjusted EBITDA, adjusted net income, adjusted net income attributable to noncontrolling interest and pro forma liquidity are non-GAAP financial measures.

The company defines adjusted operating cash flow as net cash provided by operating activities before changes in operating assets and liabilities and adjusted for cash received (paid) on financing derivatives. It defines EBITDA as net income (loss) before income tax (benefit) expense, interest expense and depreciation, depletion and amortization and accretion of asset retirement obligations. Adjusted EBITDA, as presented herein, is EBITDA excluding asset impairment, interest income, (gain) loss on derivative contracts net of cash received on settlement of derivative contracts, loss (gain) on sale of assets, transaction costs, legal settlements, consent solicitation costs, effect of annual incentive plan adoption, severance, bargain purchase gain, loss on extinguishment of debt and other various non-cash items (including non-cash portion of noncontrolling interest and stock-based compensation). Pro forma adjusted EBITDA, as presented herein, is adjusted EBITDA excluding adjusted EBITDA attributable to properties or subsidiaries sold during the period or to be sold in future periods.

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

Management also uses the supplemental financial measure of adjusted net income, which excludes tax (benefit) expense resulting from divestiture/acquisition, asset impairment, (gain) loss on derivative contracts net of cash received on settlement of derivative contracts, loss (gain) on sale of assets, transaction costs, legal settlements, consent solicitation costs, effect of annual incentive plan adoption, financing commitment fees, bargain purchase gain, loss on extinguishment of debt, severance and other non-cash items from income available (loss applicable) to common stockholders. Management uses this financial measure as an indicator of the company’s operational trends and performance relative to other oil and natural gas companies and believes it is more comparable to earnings estimates provided by securities analysts. Adjusted net income is not a measure of financial performance under GAAP and should not be considered a substitute for income available (loss applicable) to common stockholders.

The supplemental measure of adjusted net income attributable to noncontrolling interest is used by the company’s management to measure the impact on the company’s financial results of the ownership by third parties of interests in the company’s less than wholly-owned consolidated subsidiaries. Adjusted net income attributable to noncontrolling interest excludes the portion of (gain) loss on derivative contracts net of cash received on settlement of derivative contracts, legal settlement and loss on sale of assets attributable to third party ownership in less than wholly-owned consolidated subsidiaries from net income (loss) attributable to noncontrolling interest. Adjusted net income attributable to noncontrolling interest is not a measure of financial performance under GAAP and should not be considered a substitute for net income attributable to noncontrolling interest.

The supplemental measure of pro forma liquidity as presented herein is cash and cash equivalents adjusted for expected proceeds upon sale of properties or subsidiaries and funds available to be drawn under the company’s senior credit facility and is used by the company’s management to measure the company’s ability to meet its future capital funding needs.

The tables below reconcile the most directly comparable GAAP financial measures to operating cash flow, EBITDA and adjusted EBITDA, adjusted net income available to common stockholders and adjusted net income attributable to noncontrolling interest.

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


	Three Months Ended December 31,					Year Ended December 31,
	2013			2012		2013			2012
	(in thousands)
Net cash provided by operating activities	$	273,623		$	198,930	$	868,630		$	783,160
Add (deduct)
Cash received (paid) on financing derivatives		1,561			4,185		6,660			(34,518	)
Changes in operating assets and liabilities		(56,813	)		56,198		(63,681	)		166,100

Adjusted operating cash flow	$	218,371		$	259,313	$	811,609		$	914,742

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


	Three Months Ended December 31,						Year Ended December 31,
	2013			2012			2013			2012
	(in thousands)
Net income (loss)	$	19,080		$	(287,904	)	$	(553,889	)	$	141,571
Adjusted for
Income tax (benefit) expense		(1,616	)		12			5,684			(100,362	)
Interest expense ⁽¹⁾		62,155			88,793			274,591			312,869
Depreciation and amortization—other		15,508			15,729			62,136			60,805
Depreciation and depletion—oil and natural gas		133,664			175,577			567,732			568,029
Accretion of asset retirement obligations		8,726			9,371			36,777			28,996

EBITDA		237,517			1,578			393,031			1,011,908
Asset impairment		9,950			314,723			26,280			316,004
Interest income		(375	)		(450	)		(1,962	)		(1,466	)
Stock-based compensation		4,582			8,982			27,351			39,682
(Gain) loss on derivative contracts		(22,928	)		(19,712	)		47,123			(241,419	)
Cash received on settlement of derivative contracts ⁽²⁾		12,780			43,058			31,499			100,328
Other non-cash expense (income)		465			(2,151	)		189			(9,966	)
Loss (gain) on sale of assets ⁽³⁾		722			(666	)		399,086			3,089
Transaction costs		37			369			2,255			15,645
Legal settlements		(5,689	)		25,000			(4,608	)		25,000
Consent solicitation costs		499			2,420			22,834			2,420
Effect of Annual Incentive Plan adoption		—			—			14,735			—
Severance		2,130			—			122,505			—
Bargain purchase gain		—			—			—			(122,696	)
Loss on extinguishment of debt		—			19			82,005			3,075
Non-cash portion of noncontrolling interest ⁽⁴⁾		(10,575	)		(54,955	)		(142,670	)		(71,647	)

Adjusted EBITDA	$	229,115		$	318,215		$	1,019,653		$	1,069,957

Pro forma adjustments
Less EBITDA attributable to
Permian properties sold		—			(89,879	)		(50,574	)		(435,738	)
Tertiary properties sold		—			—			—			(7,996	)
Gulf of Mexico properties sold (2014)		(63,099	)		(97,862	)		(360,045	)		(260,742	)

Pro Forma Adjusted EBITDA	$	166,016		$	130,474		$	609,034		$	365,481

⁽¹⁾	Excludes non-cash gains on interest rate swaps of $2.4 million for the three-month period ended December 31, 2012 and $2.4 million and $8.1 million for the years ended December 31, 2013 and 2012, respectively.

⁽²⁾	Excludes amounts (paid) received on early settlement of derivative contracts.

⁽³⁾	Includes loss on sale of Permian oil and natural gas assets of approximately $398.9 million for the year ended December 31, 2013.

⁽⁴⁾	Represents depreciation and depletion, loss on sale of Permian Properties, (gain) loss on commodity derivative contracts net of cash received on settlement, legal settlement and income tax expense attributable to noncontrolling interests.

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA


	Three Months Ended December 31,						Year Ended December 31,
	2013			2012			2013			2012
	(in thousands)
Net cash provided by operating activities	$	273,623		$	198,930		$	868,630		$	783,160

Changes in operating assets and liabilities		(56,813	)		56,198			(63,681	)		166,100
Interest expense ⁽¹⁾		62,155			88,793			274,591			312,869
Cash received on early settlement of derivative contracts		—			—			—			(33,165	)
Cash paid on early settlement of derivative contracts - Permian		—			—			29,623			—
Transaction costs		37			369			2,255			15,645
Legal settlements		(5,689	)		25,000			(4,608	)		25,000
Consent solicitation costs		499			2,420			22,834			2,420
Effect of Annual Incentive Plan adoption		—			—			14,735			—
Severance		1,319			—			67,004			—
Noncontrolling interest - SDT ⁽²⁾		(7,275	)		(13,416	)		(39,384	)		(54,590	)
Noncontrolling interest - SDR ⁽²⁾		(13,708	)		(16,348	)		(66,372	)		(45,755	)
Noncontrolling interest - PER ⁽²⁾		(21,167	)		(18,667	)		(77,918	)		(76,564	)
Noncontrolling interest - Other ⁽²⁾		1,558			103			1,594			263
Other non-cash items		(5,424	)		(5,167	)		(9,650	)		(25,426	)


Adjusted EBITDA	$	229,115		$	318,215		$	1,019,653		$	1,069,957

⁽¹⁾	Excludes non-cash gains on interest rate swaps of $2.4 million for the three-month period ended December 31, 2012 and $2.4 million and $8.1 million for the years ended December 31, 2013 and 2012, respectively.

⁽²⁾	Excludes depreciation and depletion, loss on sale of Permian Properties, (gain) loss on derivative contracts net of cash received on settlement, legal settlement and income tax expense attributable to noncontrolling interests.

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

Income Available to Common Stockholders


	Three Months Ended December 31,						Year Ended December 31,
	2013			2012			2013			2012
	(in thousands except per share data)
Income available (loss applicable) to common stockholders	$	5,198		$	(301,785	)	$	(609,414	)	$	86,046

Tax (benefit) expense resulting from divestiture/acquisition		(860	)		—			3,842			(100,288	)
Asset impairment ⁽¹⁾		9,950			278,385			26,280			279,666
(Gain) loss on derivative contracts ⁽¹⁾		(21,449	)		(17,447	)		31,942			(207,505	)
Cash received (paid) on settlement of derivative contracts ⁽¹⁾		12,723			37,984			31,313			84,405
Loss (gain) on sale of assets ⁽¹⁾		722			(666	)		327,382			3,089
Transaction costs		37			369			2,255			15,645
Legal settlements ⁽¹⁾		(5,689	)		25,000			(4,960	)		25,000
Consent solicitation costs		499			2,420			22,834			2,420
Effect of Annual Incentive Plan adoption		—			—			14,735			—
Severance		2,130			—			122,505			—
Financing commitment fees		—			—			—			10,875
Bargain purchase gain		—			—			—			(122,696	)
Loss on extinguishment of debt		—			19			82,005			3,075
Other non-cash income		(2,203	)		(2,886	)		(4,752	)		(10,961	)
Effect of income taxes		(52	)		13			2,359			42


Adjusted net income available to common stockholders		1,006			21,406			48,326			68,813
Preferred stock dividends		13,882			13,881			55,525			55,525


Total adjusted net income	$	14,888		$	35,287		$	103,851		$	124,338


Weighted average number of common shares outstanding
Basic		483,936			476,241			481,148			453,595
Diluted ⁽²⁾		574,832			566,664			571,801			546,148
Total adjusted net income
Per share - basic	$	0.00		$	0.04		$	0.10		$	0.15

Per share - diluted	$	0.03		$	0.06		$	0.18		$	0.23

⁽¹⁾	Excludes amounts attributable to noncontrolling interests.

⁽²⁾	Weighted average fully diluted common shares outstanding for certain periods presented includes shares that are considered antidilutive for calculating earnings per share in accordance with GAAP.

Reconciliation of Net Income (Loss) Attributable to Noncontrolling Interest to Adjusted Net

Income Attributable to Noncontrolling Interest


	Three Months Ended December 31,						Year Ended December 31,
	2013			2012			2013		2012
	(in thousands)
Net income (loss) attributable to noncontrolling interest	$	30,017		$	(6,626	)	$	39,410	$	105,000
Asset impairment		—			36,338			—		36,338
Loss on sale of assets - Permian		—			—			71,704		—
Legal settlements		—			—			352		—
(Gain) loss on derivative contracts		(1,479	)		(2,265	)		15,181		(33,914	)
Cash received on settlement of derivative contracts		57			5,074			186		15,923

Adjusted net income attributable to noncontrolling interest	$	28,595		$	32,521		$	126,833	$	123,347

Reconciliation of Cash and Cash Equivalents to Pro Forma Liquidity


	December 31, 2013
	(in thousands)
Cash and cash equivalents	$	814,663
Estimated net sale proceeds - Gulf of Mexico Properties		736,714

Pro forma cash and cash equivalents	$	1,551,377
Availability under Senior Credit Facility ⁽¹⁾		745,900

Pro forma liquidity	$	2,297,277

⁽¹⁾	Reduced by letters of credit totaling $29.1 million.

Conference Call Information

The company will host a conference call to discuss these results on Friday, February 28, 2014 at 8:00 am CST. The telephone number to access the conference call from within the U.S. is 866-953-6858 and from outside the U.S. is 617-399-3482. The passcode for the call is 62015603. An audio replay of the call will be available from February 28, 2014 until 11:59 pm CST on March 28, 2014. The number to access the conference call replay from within the U.S. is 888-286-8010 and from outside the U.S. is 617-801-6888. The passcode for the replay is 34029572.

A live audio webcast of the conference call will also be available via SandRidge’s website, www.sandridgeenergy.com, under Investor Relations/Events. The webcast will be archived for replay on the company’s website for 30 days.

7^th Annual Investor/Analyst Meeting

•

March 4, 2014 (Tuesday), 8:00 am EST, at the New York Stock Exchange

Conference Participation

SandRidge Energy, Inc. will participate in the following upcoming events:

•

March 25, 2014 – Howard Weil 42^nd Annual Energy Conference; New Orleans, LA

•

April 8, 2014 – IPAA’s 20^th Annual OGIS New York; NYC, NY

•

May 13, 2014 – 2014 Barclays High Yield Conference; Phoenix, AZ

At 8:00 am Central Time on the day of each presentation, the corresponding slides and any webcast information will be accessible on the Investor Relations portion of the company’s website at www.sandridgeenergy.com. Please check the website for updates regularly as this schedule is subject to change. Also, please note that SandRidge Energy, Inc. intends for its website to be used as a reliable source of information for all future events in which it may participate as well as updated presentations regarding the company. Slides and webcasts (where applicable) will be archived and available for at least 30 days after each use or presentation.

First Quarter 2014 Earnings Release and Conference Call

May 7, 2014 (Wednesday) – Earnings press release after market close

May 8, 2014 (Thursday) – Earnings conference call at 8:00 am CST

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(in thousands, except per share data)


	Three Months Ended December 31,						Years Ended December 31,
	2013			2012			2013			2012
	(Unaudited)
Revenues
Oil, natural gas and NGL	$	428,768		$	499,907		$	1,820,278		$	1,759,282
Drilling and services		16,989			25,932			66,586			116,633
Midstream and marketing		15,450			12,620			58,304			40,486
Construction contract		96			796,323			23,349			796,323
Other		3,805			3,316			14,871			18,241

Total revenues		465,108			1,338,098			1,983,388			2,730,965

Expenses
Production		150,798			134,330			516,427			477,154
Production taxes		7,473			10,988			32,292			47,210
Cost of sales		11,680			15,759			57,118			68,227
Midstream and marketing		13,690			12,482			53,644			39,669
Construction contract		96			796,323			23,349			796,323
Depreciation and depletion - oil and natural gas		133,664			175,577			567,732			568,029
Depreciation and amortization - other		15,508			15,729			62,136			60,805
Accretion of asset retirement obligations		8,726			9,371			36,777			28,996
Impairment		9,950			314,723			26,280			316,004
General and administrative		37,750			82,884			330,425			241,682
(Gain) loss on derivative contracts		(22,928	)		(19,712	)		47,123			(241,419	)
Loss (gain) on sale of assets		722			(666	)		399,086			3,089

Total expenses		367,129			1,547,788			2,152,389			2,405,769

Income (loss) from operations		97,979			(209,690	)		(169,001	)		325,196


Other income (expense)
Interest expense		(61,780	)		(85,921	)		(270,234	)		(303,349	)
Bargain purchase gain		—			—			—			122,696
Loss on extinguishment of debt		—			(19	)		(82,005	)		(3,075	)
Other income, net		11,282			1,112			12,445			4,741

Total other expense		(50,498	)		(84,828	)		(339,794	)		(178,987	)

Income (loss) before income taxes		47,481			(294,518	)		(508,795	)		146,209
Income tax (benefit) expense		(1,616	)		12			5,684			(100,362	)

Net income (loss)		49,097			(294,530	)		(514,479	)		246,571
Less: net income (loss) attributable to noncontrolling interest		30,017			(6,626	)		39,410			105,000

Net income (loss) attributable to SandRidge Energy, Inc.		19,080			(287,904	)		(553,889	)		141,571
Preferred stock dividends		13,882			13,881			55,525			55,525

Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	$	5,198		$	(301,785	)	$	(609,414	)	$	86,046

Earnings (loss) per share
Basic	$	0.01		$	(0.63	)	$	(1.27	)	$	0.19

Diluted	$	0.01		$	(0.63	)	$	(1.27	)	$	0.19

Weighted average number of common shares outstanding
Basic		483,936			476,179			481,148			453,595

Diluted		483,936			476,179			481,148			456,015

SandRidge Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(in thousands, except per share data)


	December 31,
	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	814,663		$	309,766
Accounts receivable, net		349,218			445,506
Derivative contracts		12,779			71,022
Costs in excess of billings and contract loss		4,079			11,229
Prepaid expenses		39,253			31,319
Restricted deposit		—			255,000
Other current assets		21,831			19,043

Total current assets		1,241,823			1,142,885
Oil and natural gas properties, using full cost method of accounting
Proved (includes development and project costs excluded from amortization of $45.6 million and $72.4 million at December 31, 2013 and 2012, respectively)		10,972,816			12,262,921
Unproved		531,606			865,863
Less: accumulated depreciation, depletion and impairment		(5,762,969	)		(5,231,182	)

		5,741,453			7,897,602

Other property, plant and equipment, net		566,222			582,375
Derivative contracts		14,126			23,617
Other assets		121,171			144,252

Total assets	$	7,684,795		$	9,790,731

LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	812,488		$	766,544
Billings and contract loss in excess of costs incurred		—			15,546
Derivative contracts		34,267			14,860
Asset retirement obligations		87,063			118,504
Deposit on pending sale		—			255,000

Total current liabilities		933,818			1,170,454
Long-term debt		3,194,907			4,301,083
Derivative contracts		20,564			59,787
Asset retirement obligations		337,054			379,906
Other long-term obligations		22,825			17,046

Total liabilities		4,509,168			5,928,276

Commitments and contingencies
Equity
SandRidge Energy, Inc. stockholders’ equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2013 and December 31, 2012; aggregate liquidation preference of $265,000		3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at December 31, 2013 and December 31, 2012; aggregate liquidation preference of $200,000		2			2
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at December 31, 2013 and December 31, 2012; aggregate liquidation preference of $300,000		3			3
Common stock, $0.001 par value, 800,000 shares authorized; 491,609 issued and 490,290 outstanding at December 31, 2013 and 491,578 issued and 490,359 outstanding at December 31, 2012		483			476
Additional paid-in capital		5,298,301			5,233,019
Additional paid-in capital—stockholder receivable		(3,750	)		(5,000	)
Treasury stock, at cost		(8,770	)		(8,602	)
Accumulated deficit		(3,460,462	)		(2,851,048	)

Total SandRidge Energy, Inc. stockholders’ equity		1,825,810			2,368,853
Noncontrolling interest		1,349,817			1,493,602

Total equity		3,175,627			3,862,455

Total liabilities and equity	$	7,684,795		$	9,790,731

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)


	Years Ended December 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(514,479	)	$	246,571
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization		629,868			628,834
Accretion of asset retirement obligations		36,777			28,996
Impairment		26,280			316,004
Debt issuance costs amortization		10,091			14,388
Amortization of discount, net of premium, on long-term debt		1,036			2,592
Bargain purchase gain		—			(122,696	)
Loss on extinguishment of debt		82,005			3,075
Deferred income tax provision (benefit)		3,842			(100,288	)
Loss (gain) on derivative contracts		47,123			(241,419	)
Cash (paid) received on settlement of derivative contracts		(5,879	)		125,932
Loss on sale of assets		399,086			3,089
Stock-based compensation		85,270			42,795
Other		3,929			1,387
Changes in operating assets and liabilities increasing (decreasing) cash
Receivables		90,048			(141,534	)
Cost in excess of billings and contract loss, net		(8,396	)		(89,003	)
Prepaid expenses		(7,934	)		(5,952	)
Other current assets		810			(1,586	)
Other assets and liabilities, net		5,777			34,447
Accounts payable and accrued expenses		116,999			121,889
Asset retirement obligations		(133,623	)		(84,361	)

Net cash provided by operating activities		868,630			783,160

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment		(1,496,731	)		(2,146,372	)
Acquisitions of assets		(17,028	)		(840,740	)
Proceeds from sale of assets		2,584,115			431,167

Net cash provided by (used in) investing activities		1,070,356			(2,555,945	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		—			1,850,344
Repayments of borrowings		(1,115,500	)		(366,029	)
Premium on debt redemption		(61,997	)		(844	)
Debt issuance costs		(91	)		(48,538	)
Proceeds from issuance of royalty trust units		—			587,086
Proceeds from the sale of royalty trust units		28,985			139,360
Noncontrolling interest distributions		(206,470	)		(181,727	)
Noncontrolling interest contributions		1,579			—
Stock-based compensation excess tax benefit		(4	)		(16	)
Purchase of treasury stock		(32,976	)		(14,723	)
Dividends paid—preferred		(55,525	)		(55,525	)
Cash received on shareholder receivable		1,250			—
Cash received (paid) on settlement of financing derivative contracts		6,660			(34,518	)

Net cash (used in) provided by financing activities		(1,434,089	)		1,874,870

NET INCREASE IN CASH AND CASH EQUIVALENTS		504,897			102,085
CASH AND CASH EQUIVALENTS, beginning of year		309,766			207,681

CASH AND CASH EQUIVALENTS, end of year	$	814,663		$	309,766

Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(274,850	)	$	(257,152	)
Cash paid for income taxes		(4,610	)		(1,324	)
Supplemental Disclosure of Noncash Investing and Financing Activities
Deposit on pending sale	$	(255,000	)	$	255,000
Change in accrued capital expenditures		72,848			(27,610	)
Adjustment to oil and natural gas properties for contract loss		—			50,000
Asset retirement costs capitalized		5,078			7,479
Common stock issued in connection with acquisition		—			542,138

For further information, please contact:

Duane M. Grubert

EVP – Investor Relations and Strategy

SandRidge Energy, Inc.

123 Robert S. Kerr Avenue

Oklahoma City, OK 73102-6406

(405) 429-5515

Cautionary Note to Investors - This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, but not limited to, the information appearing under the heading “Operational Guidance.” These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include projections and estimates of net income and EBITDA, drilling plans, oil and natural gas production, derivative transactions, pricing differentials, operating costs, general and administrative costs, capital spending, plugging and abandonment costs, tax rates, liquidity, and descriptions of our development plans and appraisal programs. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of oil and natural gas prices, our success in discovering, estimating, developing and replacing oil and natural gas reserves, actual decline curves and the actual effect of adding compression to natural gas wells, the availability and terms of capital, the ability of counterparties to transactions with us to meet their obligations, our timely execution of hedge transactions, credit conditions of global capital markets, changes in economic conditions, the amount and timing of future development costs, the availability and demand for alternative energy sources, regulatory changes, including those related to carbon dioxide and greenhouse gas emissions, and other factors, many of which are beyond our control. We refer you to the discussion of risk factors in (a) Part I, Item 1A - “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2012 and (b) comparable “risk factors” sections of our Quarterly Reports on Form 10-Q filed thereafter. All of the forward-looking statements made in this press release are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to update or revise any forward-looking statements.

The SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves, as each is defined by the SEC. At times we use the term “EUR” (estimated ultimate recovery) to refer to estimates that the SEC’s guidelines prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and, accordingly, are subject to substantially greater risk of being actually realized by the company. For a discussion of the company’s proved reserves, as calculated under current SEC rules, we refer you to the company’s Annual Report on Form 10-K referenced above, which is available on our website at www.sandridgeenergy.com and at the SEC‘s website at www.sec.gov.

SandRidge Energy, Inc. is an oil and natural gas company headquartered in Oklahoma City, Oklahoma with its principal focus on exploration and production. SandRidge and its subsidiaries also own and operate gas gathering and processing facilities and conduct marketing operations. In addition, Lariat Services, Inc., a wholly-owned subsidiary of SandRidge, owns and operates a drilling rig and related oil field services business. SandRidge focuses its exploration and production activities in the Mid-Continent region of the United States. SandRidge’s internet address is www.sandridgeenergy.com.