SANDRIDGE ENERGY INC - FORM 8-K - EX-99.1

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8-K - FORM 8-K - SANDRIDGE ENERGY INC	d622787d8k.htm

Exhibit 99.1

LOGO

SandRidge Energy, Inc. Reports Financial and Operational Results for Third Quarter and First Nine Months of 2013

Increases 2013 Production Guidance by 300 MBoe to 33.6 MMBoe

Mississippian Production Averaged 47.9 MBoe per Day in the Third Quarter, a 59% Increase Year-Over-Year

Decreased Mississippian Lease Operating Expense to $7.02 per Boe in the Third Quarter, a 22% Decrease Year-Over-Year

Delivered 104 Mississippian Wells with an Average 30-day IP of 307 Boe per Day during the Third Quarter, YTD Average 30-day IP of 339 Boe per Day

Initiated Development of Chester and Stacked Mississippian Formations

Issues 2014 Guidance

- Estimated 2014 Total Production of 36.3 MMBoe, 12% Organic Growth

- Estimated Mississippian Production of 22.8 MMBoe, 35% Growth

- Planned Capital Expenditures of $1.5 Billion

Oklahoma City, Oklahoma, November 5, 2013 – SandRidge Energy, Inc. (NYSE: SD) today reported financial and operational results for the quarter and nine months ended September 30, 2013 and provided an update on the execution of its 2013 development plan.

James Bennett, SandRidge’s Chief Executive Officer and President, commented, “Over the last couple of quarters, we have pursued several key themes operationally – being more efficient with our capital, consistent Mississippian growth, reducing our costs, and identifying new opportunities. We believe we are hitting the mark on all of these. Through successful high grading efforts and operational improvements, we have increased Mississippian production from the second quarter even while reducing our rig count by 15%, again delivering more production for less capital. As a result, we are increasing full year production guidance for the second quarter in a row without increasing budgeted capital expenditures and while continuing to lower other expenses. As our Mississippian rig count ramps back up over the next few quarters, we are confident that we will be able to grow production there by approximately 35% in 2014, which will contribute to 12% year-over-year organic growth for the company and tangible organic cash flow growth. Finally, the inventory of new opportunities within our Mid-Continent asset base continues to expand as we identify new formations and stacked pays and see encouraging results in our appraisal areas.”

Key Financial Results

Third Quarter

•

Adjusted EBITDA of $252 million for third quarter 2013 compared to $297 million in third quarter 2012. Pro forma for the sale of the company’s Permian assets in the first quarter of 2013, adjusted EBITDA was $182 million for third quarter 2012.

•

Adjusted operating cash flow of $235 million for third quarter 2013 compared to $281 million in third quarter 2012.

•

Net loss applicable to common stockholders of $87 million, or $0.18 per diluted share, for third quarter 2013 compared to net loss applicable to common stockholders of $184 million, or $0.39 per diluted share, in third quarter 2012.

•

Adjusted net income of $40.4 million, or $0.07 per diluted share, for third quarter 2013 compared to adjusted net income of $29.6 million, or $0.05 per diluted share, in third quarter 2012.

Nine Months

•

Adjusted EBITDA of $790 million for the first nine months of 2013 compared to $752 million in the first nine months of 2012. Pro forma for acquisitions and divestitures, adjusted EBITDA was $740 million for the first nine months of 2013 compared to $522 million in the first nine months of 2012.

•

Adjusted operating cash flow of $593 million for the first nine months of 2013 compared to $655 million in the first nine months of 2012.

•

Net loss applicable to common stockholders of $615 million, or $1.28 per diluted share, for the first nine months of 2013 compared to net income available to common stockholders of $388 million, or $0.80 per diluted share, in the first nine months of 2012.

•

Adjusted net income of $89.3 million, or $0.16 per diluted share, for the first nine months of 2013 compared to adjusted net income of $87.6 million, or $0.16 per diluted share, in the first nine months of 2012.

Adjusted net income, adjusted EBITDA and adjusted 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 12.

Highlights

Mississippian Development Program

•

Mississippian production averaged 47.9 MBoe per day in the third quarter, a 1% sequential increase, and a 59% increase year-over-year

•

Operated an average of 22 rigs in the third quarter, 15% fewer rigs than in the second quarter, and 31% fewer rigs than in the first quarter

•

Deferred 12 high volume wells in the third quarter due to production outperforming gas infrastructure capacity. An accelerated take-away project was placed in operation on October 22, 2013 (48% oil). Of the 12 deferred wells, four were put to sales after the project was complete, currently delivering an average per well rate of 895 Boe per day. The eight remaining wells are scheduled to come on line over the next few months

Multi-pay Initiatives

•

53 Middle Mississippian wells drilled YTD have delivered an average 30-day IP of 363 Boe per day

•

Four Horizontal Chester wells drilled YTD have delivered an average 30-day IP of 274 Boe per day, supporting additional horizontal Chester development in 2014

•

Five Lower Mississippian wells drilled YTD have delivered an average 30-day IP of 240 Boe per day

•

Same section test wells in the Upper and Lower Mississippian formations outperformed expectations in Harper County, Kansas. The Upper well delivered a 30-day IP of 456 Boe per day, and the Lower well delivered a 30-day IP of 319 Boe per day. Multiple offsetting wells are scheduled for 2014

•

Launched a multi-section development of stacked Mississippian play in Grant County, Oklahoma, after Upper and Lower Mississippian test wells delivered 30-day average IPs over 400 Boe per day

•

Initiated a nine well Woodford appraisal program. Three wells have been completed to date. Two wells delivered test oil rates of 68 Bbl per day and 37 Bbl per day, and one well has produced only water. Strong industry results and key takeaways from these first tests support further testing

Appraisal Program

•

An Upper Mississippian test well in Kay County extended the Eastern boundary of the company’s Mississippian play with a 1,000 Boe per day test rate. Three additional wells are scheduled in the fourth quarter to delineate the surrounding leasehold

•

A vertical appraisal well discovered commercial pay in the Marmaton formation in Comanche County, Kansas. The well delivered a 30-day IP of 496 Boe per day. A second delineation well confirmed additional pay, and supports future multi-well horizontal development

Capital Efficiency and Cost Improvements

•

Industry leading quarterly average Mississippian well cost of $2.95 million

•

For the first nine months of 2013, drilled 340 horizontal wells and associated infrastructure and spent $647 million, versus drilling 271 horizontal wells and associated infrastructure and spending $676 million in the first nine months of 2012

•

Mississippian producer to disposal well ratio increased to 30:1 for the third quarter of 2013 through continued optimization and design improvements of current system

•

Developed and employing new low cost disposal wells. The new design is expected to save approximately $1 million over the previous design and is slated for areas outside the company’s current infrastructure

•

Implemented new centralized production battery design to serve multi-well pad developments, yielding a savings of $100,000 per horizontal well

•

Mississippian lease operating expense was $7.02 per Boe during the third quarter, a 5% sequential decrease and a 22% year-over-year decrease

Offshore

•

Licensed 25 blocks of WAZ 3D seismic data over Bullwinkle and its adjacent Miocene producing subsalt fields in Green Canyon to further analyze Miocene reservoirs beneath the Bullwinkle platform. Initiated meetings with potential industry partners to secure a suitable partner to test the objectives

•

Procuring 9 blocks of WAZ 3D seismic data in and around South Pass 60 to further analyze 3-way closure subsalt prospect. Initiated contacts with potential industry partners to explore a joint venture opportunity

Financial

•

Adjusted G&A run-rate of $144 million during the third quarter

•

Current liquidity of $1.65 billion with cash balance of approximately $900 million

•

At September 30, no borrowings were outstanding under the credit facility and the leverage ratio was 2.35x

2014 Guidance

•

12% organic production growth, adjusted for the 2013 Permian divestiture

•

24% organic liquids growth, adjusted for the 2013 Permian divestiture

•

Capital expenditures of $1.5 billion

•

Average 25 rigs in the Mississippian play and drill approximately 430 wells

•

Continue appraisal drilling and stacked pay tests

•

Midpoint for LOE unit cost represents a 9% year-over-year reduction

•

Midpoint for G&A unit cost represents a 22% year-over-year reduction

Presentation slides to be viewed in conjunction with certain of the above operational highlights will be available on the company’s website, www.sandridgeenergy.com, under Investor Relations/Presentations & Events on November 6, 2013 at 7:00 am CST. Additional 2013 and 2014 Guidance detail is available on the company’s website under Investor Relations/Guidance.

Drilling and Operational Activities

Mississippian Play. During the third quarter of 2013, SandRidge drilled 91 horizontal wells: 67 in Oklahoma and 24 in Kansas. SandRidge also drilled three 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. For the fourth quarter of 2013, the company plans to average 23 horizontal rigs in the Mississippian play: 17 in Oklahoma and six in Kansas. The company’s Mississippian assets produced 47.9 MBoe per day during the third quarter (48% oil).

Gulf of Mexico / Gulf Coast. During the third quarter of 2013, SandRidge drilled and completed two wells, one in High Island Block 31L, and the other in Green Canyon Block 108. Additionally, SandRidge performed three recompletions and participated in two non-operated recompletions during the quarter. The company’s Gulf of Mexico and Gulf Coast assets produced 26.4 MBoe per day during the quarter (50% oil). Approximately 181,000 Boe was deferred in the quarter due to pipeline curtailments and delays in securing a work barge to clear paraffin from the oil export line of Vermillion 371.

Permian Basin. In the company’s Permian properties, 56 wells were drilled during the third quarter of 2013. SandRidge plans to utilize three rigs and expects to drill approximately 210 wells in 2013. The company’s Permian Basin assets produced 6.5 MBoe per day during the quarter (96% oil).

Other Operating Areas. During the third quarter, SandRidge’s other West Texas properties produced approximately 6.8 MBoe per day (99% natural gas). Additionally, its other Mid-Continent assets produced 2.0 MBoe per day in the quarter (80% natural gas).

Royalty Trusts. At September 30, 2013, the company was obligated to drill 32 development wells for SandRidge Mississippian Trust II (“SDR”) and 251 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.

Operational and Financial Statistics

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Production
Oil (MBbl) ⁽¹⁾		3,949			4,943			12,510			12,925
Natural gas (MMcf)		25,788			27,184			78,342			64,832
Oil equivalent (MBoe)		8,247			9,473			25,567			23,730
Daily production (MBoed)		89.6			103.0			93.7			86.6
Average price per unit
Realized oil price per barrel—as reported ⁽¹⁾	$	95.71		$	84.50		$	90.18		$	86.25
Realized impact of derivatives per barrel ⁽¹⁾		(5.30	)		7.34			0.93			3.39

Net realized price per barrel ⁽¹⁾	$	90.41		$	91.84		$	91.11		$	89.64

Realized natural gas price per Mcf—as reported	$	3.15		$	2.60		$	3.36		$	2.23
Realized impact of derivatives per Mcf		0.30			(0.37	)		0.08			0.08

Net realized price per Mcf	$	3.45		$	2.23		$	3.44		$	2.31

Realized price per Boe—as reported	$	55.68		$	51.54		$	54.43		$	53.07

Net realized price per Boe—including impact of derivatives	$	54.08		$	54.32		$	55.11		$	55.14

Average cost per Boe
Lease operating	$	14.10		$	14.47		$	14.30		$	14.45
Production taxes		1.07			1.37			0.97			1.53
General and administrative
General and administrative, excluding stock-based compensation ⁽²⁾		4.01			3.90			8.35			5.30
Stock-based compensation ⁽³⁾		0.84			1.04			3.10			1.40
Depletion ⁽⁴⁾		17.72			18.49			18.07			17.36
Lease operating cost per Boe
Mississippian	$	7.02		$	9.05		$	7.77		$	9.32
Offshore		25.71			23.61			23.09			22.91
Earnings per share
(Loss) earnings per share applicable to common stockholders
Basic	$	(0.18	)	$	(0.39	)	$	(1.28	)	$	0.87
Diluted		(0.18	)		(0.39	)		(1.28	)		0.80
Adjusted net income per share available to common stockholders
Basic	$	0.05		$	0.03		$	0.10		$	0.10
Diluted		0.07			0.05			0.16			0.16
Weighted average number of common shares outstanding (in thousands)
Basic		483,582			476,037			480,209			445,991
Diluted ⁽⁵⁾		573,716			566,551			571,354			537,300

⁽¹⁾	Includes NGLs.

⁽²⁾

Includes transaction costs, legal settlements, severance, annual incentive plan adoption effect and consent solicitation costs totaling $2.7 million and $102.2 million for the three and nine-month periods ended September 30, 2013, respectively. Includes transaction costs totaling $0.6 million and $13.7 million for the three and nine-month periods ended September 30, 2012, respectively.

⁽³⁾	Three and nine-month periods ended September 30, 2013 include $1.7 million and $54.7 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 Third Quarter 2013 Financial Results

Oil and natural gas revenue decreased 6% to $459 million in the third quarter of 2013 from $488 million in the same period of 2012 primarily as a result of a 13% decrease in total production due to the Permian divestiture that closed during the first quarter of 2013. Excluding the impact of the Permian divestiture, production grew approximately 13% as result of continued development of the company’s properties in the Mississippian play. Mississippian production accounted for 53% of the company’s total production in third quarter 2013 compared to 30% in third quarter 2012. Realized reported prices, which exclude the impact of derivative settlements, were $95.71 per barrel and $3.15 per Mcf during the third quarter of 2013 compared to $84.50 per barrel and $2.60 per Mcf during the same period in 2012.

Third quarter 2013 production expense was $14.10 per Boe compared to third quarter 2012 production expense of $14.47 per Boe. The decrease was primarily attributable to improving efficiencies in SandRidge’s primary onshore operations in the Mississippian play where production expense decreased 22% year-over-year from $9.05 to $7.02 per Boe.

General and administrative expenses totaled $40 million in the third quarter of 2013 and included approximately $4 million of severance costs and consent solicitation costs (annualized pro forma run-rate of $144 million), representing a sequential decrease of 20% from the previous quarter general and administrative expenses, excluding charges for severance, transactions, consent solicitation and changes to incentive plans.

Capital Expenditures

The table below summarizes the company’s capital expenditures for the three and nine-month periods ended September 30, 2013 and 2012:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Drilling and production
Mid-Continent	$	188,374		$	240,642		$	647,019		$	676,078
Permian Basin		44,309			181,072			155,903			524,378
Gulf of Mexico/Gulf Coast		47,708			51,045			161,700			104,377
WTO/Tertiary/Other		—			4,576			—			20,749

		280,391			477,335			964,622			1,325,582
Leasehold and seismic
Mid-Continent		13,526			19,790			52,611			164,415
Permian Basin		—			4,267			—			12,908
Gulf of Mexico/Gulf Coast		723			2,963			2,072			12,892
WTO/Tertiary/Other		1,370			110			3,832			2,283

		15,619			27,130			58,515			192,498
Inventory		(3,351	)		(4,274	)		(14,384	)		(8,001	)
Total exploration and development		292,659			500,191			1,008,753			1,510,079

Drilling and oil field services		3,142			14,571			4,657			28,323
Midstream		16,551			20,229			46,883			61,958
Other—general		10,230			25,067			38,159			91,410

Total capital expenditures, excluding acquisitions		322,582			560,058			1,098,452			1,691,770

Acquisitions		6,925			75,444			15,527			837,019

Total capital expenditures	$	329,507		$	635,502		$	1,113,979		$	2,528,789

Plugging and abandonment	$	35,243		$	39,491		$	107,560		$	64,633

Derivative Contracts

The table below sets forth the company’s consolidated oil and natural gas price and basis swaps and collars for the fourth quarter of 2013 and the years 2014 and 2015 as of November 1, 2013 and include contracts that have been novated to or the benefits of which have been conveyed to SandRidge sponsored royalty trusts. Since August 1, 2013, the company has added approximately 4.2 million barrels of oil swaps at an average price of $92.64 per barrel across the periods presented in the table below.


	Quarter Ending		Year Ending
	12/31/2013		12/31/2014		12/31/2015
Oil (MMBbls):
Swap Volume		3.49		8.81		7.98
Swap	$	99.48	$	92.98	$	86.13
Collar Volume		0.04		—		—
Collar: High	$	102.50		—		—
Collar: Low	$	80.00		—		—
Three-way Collar Volume		—		8.21		2.92
Call Price		—	$	100.00	$	103.13
Put Price		—	$	90.20	$	90.82
Short Put Price		—	$	70.00	$	73.13
Natural Gas (Bcf):
Swap Volume		12.42		—		—
Swap	$	4.11		—		—
Collar Volume		1.72		0.94		1.01
Collar: High	$	6.71	$	7.78	$	8.55
Collar: Low	$	3.78	$	4.00	$	4.00

Balance Sheet

The company’s capital structure at September 30, 2013 and December 31, 2012 is presented below:


	September 30,			December 31,
	2013			2012
	(in thousands)
Cash and cash equivalents	$	920,257		$	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		444,580			444,127
7.5% Senior Notes due 2021		1,179,027			1,179,328
8.125% Senior Notes due 2022		750,000			750,000
7.5% Senior Notes due 2023, net		821,177			820,971

Total debt		3,194,784			4,301,083
Stockholders’ equity
Preferred stock		8			8
Common stock		483			476
Additional paid-in capital		5,287,792			5,228,019
Treasury stock, at cost		(8,763	)		(8,602	)
Accumulated deficit		(3,465,661	)		(2,851,048	)

Total SandRidge Energy, Inc. stockholders’ equity		1,813,859			2,368,853

Noncontrolling interest		1,371,689			1,493,602
Total capitalization	$	6,380,332		$	8,163,538

During the third quarter of 2013, the company’s debt, net of cash balances, increased by approximately $175 million as a result of funding the company’s drilling program. On November 1, 2013, the company had no amount drawn under its $775 million senior credit facility and approximately $900 million of cash, leaving approximately $1.65 billion of available liquidity. The company was in compliance with all applicable covenants contained in its debt agreements during the nine months ended September 30, 2013 and through and as of the date of this release.

2013 Operational Guidance Update

The company is updating certain 2013 guidance provided on August 6, 2013. The company is updating its liquids production guidance to reflect oil and natural gas liquids separately. Estimated total production has increased from 33.3 MMBoe to 33.6 MMBoe due to improved well performance in the company’s Mississippian and Permian assets as well as minimal hurricane related downtime in the company’s offshore assets, partly offset by offshore pipeline curtailments. G&A guidance presented for 2013 excludes one-time items. Additional 2013 Guidance detail is available on the company’s website, www.sandridgeenergy.com, under Investor Relations/Guidance.


	Year Ending December 31, 2013
	Projection as of			Projection as of
	August 6, 2013			November 5, 2013
Production
Oil (MMBbls)					*14.2*
Natural Gas Liquids (MMBbls)					*2.2*

Total Liquids (MMBbls)		16.3			*16.5*
Natural Gas (Bcf)		102.0			*102.6*

Total (MMBoe)		33.3			*33.6*
Price Realization
Oil (differential below NYMEX WTI) ⁽¹⁾	$	9.50		$	*0.50*
Natural Gas Liquids (realized % of NYMEX WTI)					33	%
Natural Gas (differential below NYMEX Henry Hub)	$	0.45		$	*0.40*
Costs per Boe
Lifting	$	14.50 - $16.50		$	14.50 - $16.50
Production Taxes		1.00 - 1.20			*0.95 - 1.05*
DD&A - oil & gas		17.10 - 18.90			17.10 - 18.90
DD&A - other		2.00 - 2.20			*1.80 - 2.00*

Total DD&A	$	19.10 - $21.10		$	*18.90 - $20.90*
G&A - cash		4.05 - 4.50			*4.00 - 4.45*
G&A - stock		1.05 - 1.20			*0.85 - 0.95*

Total G&A	$	5.10 - $5.70		$	*4.85 - $5.40*
Interest Expense	$	8.10 - $9.10		$	*7.80 - $8.65*
EBITDA from Oilfield Services, Midstream and Other ($ in millions) ⁽²⁾	$	20		$	25
Adjusted Net Income Attributable to Noncontrolling Interest ($ in millions) ⁽³⁾	$	140		$	*130*
P&A Cash Cost ($ in millions)	$	120		$	120
Corporate Tax Rate ⁽⁴⁾		0	%		0	%
Deferral Rate		0	%		0	%
Capital Expenditures ($ in millions)
Exploration and Production	$	1,230		$	1,230
Land and Seismic		100			100

Total Exploration and Production	$	1,330		$	1,330
Oil Field Services		15			10
Midstream and Other		105			*110*

Total Capital Expenditures (excluding acquisitions)	$	1,450		$	1,450

⁽¹⁾	Projection as of August 6, 2013, includes NGLs.

⁽²⁾

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.

⁽³⁾

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.

⁽⁴⁾	As a result of the Permian divestiture, the company expects to incur cash income taxes of approximately $7 million in 2013 with a corresponding expense included in Net Income.

2014 Operational Guidance

The company is initiating 2014 guidance with total production of 36.3 MMBoe, or 12% organic growth, and capital expenditures of $1.5 billion. Production growth is being driven by the company’s Mississippian assets where it anticipates generating 35% year-over-year growth. The company plans to spend approximately $920 million on Mid-Continent/Mississippian focus area drilling and approximately $45 million on appraisal drilling outside its focus acreage. The company expects to begin the year with 23 rigs and ramp up to 26 by mid-year and to drill approximately 430 horizontal wells in its focus area in 2014. The company also plans to spend approximately $115 million on Gulf of Mexico drilling and recompletions, anticipating a production decline of 15%—20% year-over-year. Additionally, the company plans to spend approximately $110 million on its Permian assets to satisfy the drilling obligation to SandRidge Permian Trust and grow annual production by approximately 10%. In total, SandRidge expects to spend approximately $140 million related to royalty trust drilling obligations in 2014 and anticipates that it will have all drilling obligations completed by the end of 2014. Additional 2014 Guidance detail is available on the company’s website, www.sandridgeenergy.com, under Investor Relations/Guidance.


	Year Ending December 31, 2014
	Projection as of
	November 5, 2013
Production
Oil (MMBbls)		15.4
Natural Gas Liquids (MMBbls)		3.9

Total Liquids (MMBbls)		19.3
Natural Gas (Bcf)		102.0

Total (MMBoe)		36.3
Price Realization
Oil (differential below NYMEX WTI)	$	1.00
Natural Gas Liquids (realized % of NYMEX WTI)		34	%
Natural Gas (differential below NYMEX Henry Hub)	$	0.70
Costs per Boe
Lifting	$	13.15 - $15.15
Production Taxes		0.95 - 1.15
DD&A - oil & gas		16.80 - 18.80
DD&A - other		1.80 - 2.00

Total DD&A	$	18.60 - $20.80
G&A - cash		2.90 - 3.20
G&A - stock		0.85 - 1.05

Total G&A	$	3.75 - $4.25
Interest Expense	$	7.00 - $8.00
EBITDA from Oilfield Services, Midstream and Other ($ in millions) ⁽¹⁾	$	25
Adjusted Net Income Attributable to Noncontrolling Interest ($ in millions) ⁽²⁾	$	120
P&A Cash Cost ($ in millions)	$	60
Corporate Tax Rate		0	%
Deferral Rate		0	%
Capital Expenditures ($ in millions)
Exploration and Production	$	1,265
Land and Seismic		110

Total Exploration and Production	$	1,375
Oil Field Services		15
Midstream and Other		110

Total Capital Expenditures (excluding acquisitions)	$	1,500

⁽¹⁾

⁽²⁾

Non-GAAP Financial Measures

Adjusted operating cash flow, adjusted EBITDA, adjusted net income and adjusted net income attributable to noncontrolling interest 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 (paid) received on financing derivatives. It defines EBITDA as net (loss) income before income tax expense (benefit), 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, (gains) losses on early settlements of derivative contracts, non-cash losses due to amendment of derivative contracts, non-cash losses due to contractual maturity of financing derivative contracts, loss 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, stock-based compensation and losses (gains) due to changes in fair value of derivative contracts).

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 expense (benefit) resulting from divestiture (acquisition), asset impairment, losses (gains) due to changes in fair value of derivative contracts, (gains) losses on early settlements of derivative contracts, non-cash losses due to amendment of derivative contracts, non-cash losses due to contractual maturity of financing derivative contracts, 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 loss on sale of assets from (loss applicable) income available 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 (loss applicable) income available 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 losses (gains) due to changes in fair value of derivative contracts, legal settlement and (gain) loss on sale of assets attributable to third party ownership in less than wholly-owned consolidated subsidiaries from net income 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 tables below reconcile the most directly comparable GAAP financial measures to adjusted operating cash flow, EBITDA and adjusted EBITDA, adjusted net income, and adjusted net income attributable to noncontrolling interest.

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013			2012 ⁽¹⁾
	(in thousands)
Net cash provided by operating activities	$	210,324		$	166,524	$	595,007		$	584,230
Add (deduct)
Cash (paid) received on financing derivatives		(629	)		6,609		5,099			(38,703	)
Changes in operating assets and liabilities		25,737			108,290		(6,868	)		109,908

Adjusted operating cash flow	$	235,432		$	281,423	$	593,238		$	655,435

⁽¹⁾

Includes retrospective application of acquisition purchase price adjustments recorded in fourth quarter of 2012.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012 ⁽¹⁾
	(in thousands)
Net (loss) income	$	(73,193	)	$	(170,420	)	$	(572,969	)	$	429,474
Adjusted for
Income tax expense (benefit)		2,363			173			7,300			(100,373	)
Interest expense ⁽²⁾		61,793			84,403			212,436			224,076
Depreciation and amortization—other		15,270			16,497			46,628			46,357
Depreciation and depletion—oil and natural gas		137,639			166,126			434,068			392,452
Accretion of asset retirement obligations		8,472			9,053			28,051			19,625

EBITDA		152,344			105,832			155,514			1,011,611
Asset impairment		687			—			16,330			—
Interest income		(408	)		(476	)		(1,587	)		(1,016	)
Stock-based compensation		5,135			9,125			22,769			30,700
Losses (gains) due to changes in fair value of derivative contracts		119,605			220,433			56,085			(234,705	)
Gains on early settlements of derivative contracts		—			(2,115	)		(323	)		(59,465	)
Losses on early settlements of derivative contracts—Permian		—			—			29,623			—
Non-cash losses due to amendment of derivative contracts		—			—			—			117,108
Non-cash losses due to contractual maturity of financing derivative contracts		707			3,055			667			6,866
Other non-cash (income) expense		(328	)		(931	)		2,119			(2,183	)
Loss on sale of assets ⁽³⁾		539			375			398,364			3,755
Transaction costs		589			681			2,218			15,276
Legal settlements		—			—			1,081			—
Consent solicitation costs		1,516			—			22,335			—
Effect of Annual Incentive Plan adoption		—			—			14,735			—
Severance		2,258			—			120,375			—
Bargain purchase gain		—			—			—			(122,696	)
Loss on extinguishment of debt		—			3,056			82,005			3,056
Non-cash portion of noncontrolling interest ⁽⁴⁾		(30,174	)		(41,545	)		(132,095	)		(16,692	)

Adjusted EBITDA	$	252,470		$	297,490		$	790,215		$	751,615

Less: EBITDA attributable to
Permian properties sold		—			(115,744	)		(50,574	)		(345,858	)
Tertiary properties sold		—			—			—			(7,996	)
Add: EBITDA attributable to (1/1 to date of acquisition)
Dynamic Offshore		—			—			—			107,647
Gulf of Mexico Properties		—			—			—			16,251

Pro forma adjusted EBITDA	$	252,470		$	181,746		$	739,641		$	521,659

⁽¹⁾

Includes retrospective application of acquisition purchase price adjustments recorded in fourth quarter of 2012.

⁽²⁾

Excludes gain due to changes in fair value of interest rate swaps of $2.0 million for the three-month period ended September 30, 2012. Excludes gains due to changes in fair value of interest rate swaps of $2.4 million and $5.6 million for the nine-month periods ended September 30, 2013 and 2012, respectively.

⁽³⁾

Includes loss on sale of Permian oil and natural gas assets of approximately $398.9 million for the nine-month period ended September 30, 2013.

⁽⁴⁾

Represents depreciation and depletion, loss on sale of Permian Properties, (gains) losses due to changes in fair value of commodity derivative contracts, legal settlement and income tax expense attributable to noncontrolling interests.

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012 ⁽¹⁾
	(in thousands)
Net cash provided by operating activities	$	210,324		$	166,524		$	595,007		$	584,230
Changes in operating assets and liabilities		25,737			108,290			(6,868	)		109,908
Interest expense ⁽²⁾		61,793			84,403			212,436			224,076
Gains on early settlements of derivative contracts		—			(2,115	)		(323	)		(33,165	)
Losses on early settlements of derivative contracts—Permian		—			—			29,623			—
Transaction costs		589			681			2,218			15,276
Legal settlements		—			—			1,081			—
Consent solicitation costs		1,516			—			22,335			—
Effect of Annual Incentive Plan adoption		—			—			14,735			—
Severance		598			—			65,685			—
Noncontrolling interest—SDT ⁽³⁾		(8,841	)		(13,933	)		(32,109	)		(41,174	)
Noncontrolling interest—SDR ⁽³⁾		(15,648	)		(16,537	)		(52,664	)		(29,407	)
Noncontrolling interest—PER ⁽³⁾		(21,908	)		(21,794	)		(56,751	)		(57,897	)
Noncontrolling interest—Other ⁽³⁾		31			51			36			160
Other non-cash items		(1,721	)		(8,080	)		(4,226	)		(20,392	)

Adjusted EBITDA	$	252,470		$	297,490		$	790,215		$	751,615

⁽¹⁾

Includes retrospective application of acquisition purchase price adjustments recorded in fourth quarter of 2012.

⁽²⁾

⁽³⁾

Excludes depreciation and depletion, loss on sale of Permian Properties, (gains) losses due to changes in fair value of commodity derivative contracts, legal settlement and income tax expense attributable to noncontrolling interests.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012 ⁽¹⁾
	(in thousands except per share data)
(Loss applicable) income available to common stockholders	$	(87,074	)	$	(184,301	)	$	(614,613	)	$	387,830
Tax expense (benefit) resulting from divestiture (acquisition)		687			—			4,702			(100,288	)
Asset impairment		687			—			16,330			—
Losses (gains) due to changes in fair value of derivative contracts ⁽²⁾		103,179			195,422			39,297			(213,905	)
Gains on early settlements of derivative contracts		—			(2,115	)		(323	)		(59,465	)
Losses on early settlements of derivative contracts—Permian		—			—			29,623			—
Non-cash losses due to amendment of derivative contracts		—			—			—			117,108
Non-cash losses due to contractual maturity of financing derivative contracts		707			3,055			667			6,866
Loss on sale of assets ⁽²⁾		575			375			326,660			3,755
Transaction costs		589			681			2,218			15,276
Legal settlements ⁽²⁾		—			—			729			—
Consent solicitation costs		1,516			—			22,335			—
Effect of Annual Incentive Plan adoption		—			—			14,735			—
Severance		2,258			—			120,375			—
Financing commitment fees		—			—			—			10,875
Bargain purchase gain		—			—			—			(122,696	)
Loss on extinguishment of debt		—			3,056			82,005			3,056
Other non-cash income		—			(658	)		(154	)		(2,443	)
Effect of income taxes		3,359			217			3,057			(47	)

Adjusted net income available to common stockholders		26,483			15,732			47,643			45,922
Preferred stock dividends		13,881			13,881			41,644			41,644

Total adjusted net income	$	40,364		$	29,613		$	89,287		$	87,566

Weighted average number of common shares outstanding
Basic		483,582			476,037			480,209			445,991
Diluted ⁽³⁾		573,716			566,551			571,354			537,300
Total adjusted net income
Per share—basic	$	0.05		$	0.03		$	0.10		$	0.10

Per share—diluted	$	0.07		$	0.05		$	0.16		$	0.16

⁽¹⁾

Includes retrospective application of acquisition purchase price adjustments recorded in fourth quarter of 2012.

⁽²⁾

Excludes amounts attributable to noncontrolling interests.

⁽³⁾

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 Attributable to Noncontrolling Interest to Adjusted Net Income Attributable to

Noncontrolling Interest


	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013		2012
	(in thousands)
Net income attributable to noncontrolling interest	$	16,191		$	10,668	$	9,393	$	111,626
(Gain) loss on sale of assets—Permian		(36	)		—		71,704		—
Legal settlement		—			—		352		—
Losses (gains) due to changes in fair value of derivative contracts		16,426			25,011		16,788		(20,800	)

Adjusted net income attributable to noncontrolling interest	$	32,581		$	35,679	$	98,237	$	90,826

Conference Call Information

The company will host a conference call to discuss these results on Wednesday, November 6, 2013 at 8:00 am CST. The telephone number to access the conference call from within the U.S. is 866-318-8618 and from outside the U.S. is 617-399-5137. The passcode for the call is 47127609. An audio replay of the call will be available from November 6, 2013 until 11:59 pm CST on December 5, 2013. 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 17857539.

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

Conference Participation

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

•

November 14, 2013 – UBS Boston Energy Mini-Conference; Boston, MA

•

December 11, 2013 – Capital One Southcoast 2013 December Energy Conference; New Orleans, LA

•

January 9, 2014 – Goldman Sachs 2014 Global Energy Conference; Miami, FL

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.

Fourth Quarter and Year End 2013 Earnings Release and Conference Call

February 27, 2014 (Thursday) – Earnings press release after market close

February 28, 2014 (Friday) – Earnings conference call at 8:00 am Central

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(in thousands, except per share data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012⁽¹⁾
	(Unaudited)
Revenues
Oil and natural gas	$	459,211		$	488,252		$	1,391,510		$	1,259,375
Drilling and services		16,149			27,760			49,597			90,701
Midstream and marketing		14,624			10,708			42,854			27,866
Construction contract		—			—			23,253			—
Other		3,619			6,078			11,066			14,925

Total revenues		493,603			532,798			1,518,280			1,392,867
Expenses
Production		116,317			137,033			365,629			342,824
Production taxes		8,816			12,967			24,819			36,222
Cost of sales		13,773			15,666			45,438			52,468
Midstream and marketing		13,224			10,674			39,954			27,187
Construction contract		—			—			23,253			—
Depreciation and depletion—oil and natural gas		137,639			166,126			434,068			392,452
Depreciation and amortization—other		15,270			16,497			46,628			46,357
Accretion of asset retirement obligations		8,472			9,053			28,051			19,625
Impairment		687			—			16,330			—
General and administrative		39,970			46,781			292,675			158,798
Loss (gain) on derivative contracts		132,808			193,497			70,051			(221,707	)
Loss on sale of assets		539			375			398,364			3,755

Total expenses		487,515			608,669			1,785,260			857,981

Income (loss) from operations		6,088			(75,871	)		(266,980	)		534,886

Other income (expense)
Interest expense		(61,385	)		(81,894	)		(208,454	)		(217,428	)
Bargain purchase gain		—			—			—			122,696
Loss on extinguishment of debt		—			(3,056	)		(82,005	)		(3,056	)
Other income, net		658			1,242			1,163			3,629

Total other expense		(60,727	)		(83,708	)		(289,296	)		(94,159	)

(Loss) income before income taxes		(54,639	)		(159,579	)		(556,276	)		440,727
Income tax expense (benefit)		2,363			173			7,300			(100,373	)

Net (loss) income		(57,002	)		(159,752	)		(563,576	)		541,100
Less: net income attributable to noncontrolling interest		16,191			10,668			9,393			111,626

Net (loss) income attributable to SandRidge Energy, Inc.		(73,193	)		(170,420	)		(572,969	)		429,474
Preferred stock dividends		13,881			13,881			41,644			41,644

(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(87,074	)	$	(184,301	)	$	(614,613	)	$	387,830

(Loss) earnings per share
Basic	$	(0.18	)	$	(0.39	)	$	(1.28	)	$	0.87

Diluted	$	(0.18	)	$	(0.39	)	$	(1.28	)	$	0.80

Weighted average number of common shares outstanding
Basic		483,582			476,037			480,209			445,991

Diluted		483,582			476,037			480,209			537,300

⁽¹⁾	Includes retrospective application of acquisition purchase price adjustments recorded in fourth quarter of 2012.

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(in thousands, except per share data)


	September 30,			December 31,
	2013			2012
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	920,257		$	309,766
Accounts receivable, net		390,882			445,506
Derivative contracts		8,306			71,022
Costs in excess of billings and contract loss		6,276			11,229
Prepaid expenses		37,857			31,319
Restricted deposit		—			255,000
Other current assets		39,684			19,043

Total current assets		1,403,262			1,142,885
Oil and natural gas properties, using full cost method of accounting
Proved		10,663,810			12,262,921
Unproved		529,032			865,863
Less: accumulated depreciation, depletion and impairment		(5,643,158	)		(5,231,182	)

		5,549,684			7,897,602

Other property, plant and equipment, net		576,390			582,375
Derivative contracts		15,478			23,617
Other assets		124,630			144,252

Total assets	$	7,669,444		$	9,790,731

LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	774,115		$	766,544
Billings and contract loss in excess of costs incurred		—			15,546
Derivative contracts		36,471			14,860
Asset retirement obligations		71,446			118,504
Deposit on pending sale		—			255,000

Total current liabilities		882,032			1,170,454
Long-term debt		3,194,784			4,301,083
Derivative contracts		24,542			59,787
Asset retirement obligations		358,301			379,906
Other long-term obligations		24,237			17,046

Total liabilities		4,483,896			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 September 30, 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 September 30, 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 September 30, 2013 and December 31, 2012; aggregate liquidation preference of $300,000		3			3
Common stock, $0.001 par value, 800,000 shares authorized; 491,805 issued and 490,536 outstanding at September 30, 2013 and 491,578 issued and 490,359 outstanding at December 31, 2012		483			476
Additional paid-in capital		5,292,792			5,233,019
Additional paid-in capital—stockholder receivable		(5,000	)		(5,000	)
Treasury stock, at cost		(8,763	)		(8,602	)
Accumulated deficit		(3,465,661	)		(2,851,048	)

Total SandRidge Energy, Inc. stockholders’ equity		1,813,859			2,368,853
Noncontrolling interest		1,371,689			1,493,602

Total equity		3,185,548			3,862,455

Total liabilities and equity	$	7,669,444		$	9,790,731

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(in thousands)


	Nine Months Ended September 30,
	2013			2012⁽¹⁾
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(563,576	)	$	541,100
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization		480,696			438,809
Accretion of asset retirement obligations		28,051			19,625
Impairment		16,330			—
Debt issuance costs amortization		7,730			11,348
Amortization of discount, net of premium, on long-term debt		913			1,940
Bargain purchase gain		—			(122,696	)
Loss on extinguishment of debt		82,005			3,056
Deferred income tax provision (benefit)		4,702			(100,288	)
Loss (gain) due to change in fair value of derivative contracts		56,085			(234,705	)
Loss due to amendment of derivative contracts		—			117,108
Gain due to contractual maturity of financing derivative contracts		(3,963	)		(17,783	)
Loss on sale of assets		398,364			3,755
Stock-based compensation		79,317			33,128
Other		1,485			(259	)
Changes in operating assets and liabilities		6,868			(109,908	)

Net cash provided by operating activities		595,007			584,230

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment		(1,163,539	)		(1,625,737	)
Acquisitions of assets		(15,527	)		(837,019	)
Proceeds from sale of assets		2,567,355			422,171

Net cash provided by (used in) investing activities		1,388,289			(2,040,585	)

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	)		(825	)
Debt issuance costs		(91	)		(48,220	)
Proceeds from issuance of royalty trust units		—			587,086
Proceeds from sale of royalty trust units		28,985			123,548
Noncontrolling interest distributions		(153,002	)		(127,023	)
Stock-based compensation excess tax benefit		(4	)		8
Purchase of treasury stock		(31,270	)		(12,807	)
Dividends paid—preferred		(45,025	)		(45,025	)
Cash received (paid) on settlement of financing derivative contracts		5,099			(38,703	)

Net cash (used in) provided by financing activities		(1,372,805	)		1,922,354

NET INCREASE IN CASH AND CASH EQUIVALENTS		610,491			465,999
CASH AND CASH EQUIVALENTS, beginning of year		309,766			207,681

CASH AND CASH EQUIVALENTS, end of period	$	920,257		$	673,680

Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(248,233	)	$	(181,386	)
Cash paid for income taxes	$	(2,911	)	$	(1,324	)
Supplemental Disclosure of Noncash Investing and Financing Activities
Deposit on pending sale	$	(255,000	)	$	—
Change in accrued capital expenditures	$	(65,087	)	$	66,033
Adjustment to oil and natural gas properties for estimated contract loss	$	—		$	10,000
Asset retirement costs capitalized	$	4,145		$	5,363
Common stock issued in connection with acquisition	$	—		$	542,138

⁽¹⁾	Includes retrospective application of acquisition purchase price adjustments recorded in fourth quarter of 2012.

For further information, please contact:

Investor Relations

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 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.

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, Gulf of Mexico, West Texas and Gulf Coast regions. SandRidge’s internet address is www.sandridgeenergy.com.

SANDRIDGE ENERGY INC - FORM 8-K - EX-99.1 - November 5, 2013

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