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

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Exhibit 99.1

SandRidge Energy, Inc. Reports Financial and Operational Results for

Fourth Quarter and the Full Year of 2016

Oklahoma City, Oklahoma, February 22, 2017 – SandRidge Energy, Inc. (the “Company” or “SandRidge”) (NYSE:SD) today announced financial and operational results for the quarter and fiscal year ended December 31, 2016. The Company will host a conference call to discuss these results on February 23^rd at 8:00 a.m. CT (877-201-0168, International: 647-788-4901—passcode: 53513467). Presentation slides will be available on the Company’s website, www.sandridgeenergy.com, under Investor Relations/Events.

Production in the quarter ending December 31, 2016 was 4.3 MMBoe (47.2 MBoepd, 28% oil, 23% NGLs, 49% natural gas), and 19.4 MMBoe for the full year, at the high end of guidance (19.0-19.4 MMBoe). During the quarter, one drilling rig was active in Oklahoma targeting the Meramec and Osage formations, with the Company also completing wells in the Niobrara North Park Basin of Colorado. Capital expenditures were $41 million during the quarter, bringing the total for the year to $202 million (excluding acquisitions) compared to prior 2016 guidance of $220-$240 million. In February 2017, the Company closed an approximately 13,100 acre acquisition (including 700 Boepd of production) in Woodward County, Oklahoma for $48 million cash, increasing its position in the northwest portion of the Sooner Trend Anadarko Basin Canadian and Kingfisher Counties play (NW STACK) to 60,000 net acres. Capital expenditures and operational guidance for 2017 is included in this release.

The Company reported a net loss of $334 million, which included a non-cash ceiling test impairment charge of $319 million. Net cash from operating activities were $66 million for the fourth quarter of 2016. When adjusting these reported amounts for items that are typically excluded by the investment community on the basis that such items affect the comparability of results, the Company’s “adjusted net income” amounted to $29 million and “adjusted operating cash flow” totaled $52 million. Earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for certain other items, otherwise referred to as “adjusted EBITDA”, for the fourth quarter was $71 million, and for the full year of 2016 was $238 million.

The Company has defined and reconciled certain Non-GAAP financial measures including adjusted net income, adjusted operating cash flow, adjusted EBITDA, PV-10 and current net debt, to the most directly comparable GAAP financial measures in supporting tables at the conclusion of this press release under the “Non-GAAP Financial Measures” beginning on page 17.

James Bennett, SandRidge President and CEO said, “After recently increasing our NW STACK position to 60,000 net acres, we will be weighting near term Mid-Continent drilling activity towards the Meramec and Osage, adding a second rig in the spring. Our track record of capturing efficiency gains can now be applied to our portfolio of Oklahoma’s NW STACK and Mississippian plays, and in the North Park Basin in Colorado, where Niobrara drilling will resume mid year. Our plan calls for oil production growth by late 2017, with a focus on EBITDA and resource value creation rather than BOE volume growth. With our strong balance sheet and liquidity in excess of $500 million, I believe SandRidge has compelling, multi-year opportunities to add shareholder value.”

Highlights during and subsequent to the fourth quarter include:

SEC Reserves of 164 MMBoe at December 31, 2016 with PV-10 of $438 Million (equal to Standardized Measure); Updated Proved Reserves of 184 MMBoe with $946 Million PV-10 at Recent Strip Pricing

Acquisition of ~13,100 Net Acres (Including ~700 Boepd of Production) in Woodward County, Oklahoma with Meramec and Osage Focus for $48 Million in Cash, Increasing NW STACK Position to 60,000 Net Acres

901 Boepd (91% Oil) 30-Day IP on First Niobrara XRL and 539 Boepd (92% Oil) on First Niobrara “C” Bench Well

925 Boepd (77% Oil) 30-Day IP Major County Meramec Well in NW STACK

One Rig Active and Second Rig Starting Late Q1’17 in NW STACK Drilling in Major, Woodward, and Garfield Counties, One Rig Active in North Park at Mid Year

New $600 Million Reserve-based Credit Facility with $425 Million Conforming Borrowing Base

All Outstanding Mandatorily Convertible Notes Converted, 35.9 Million Shares Outstanding as of February 20, 2017

Current Capital Structure

•

35.9 million shares outstanding

•

New $600 million reserve-based credit facility with $425 million conforming borrowing base

•

Liquidity of $537 million including ~$120 million of cash and $417 million capacity under the credit facility, net of outstanding letters of credit

•

Outstanding debt consists of a $36 million par value note secured by the Company’s real estate in Oklahoma City, resulting in zero current net debt

Entering into the new credit facility in February 2017 triggered the release of $50 million of cash held in escrow to the Company and the conversion of all of the $264 million outstanding mandatorily convertible notes into approximately 14.1 million shares of the Company’s common stock.

2017 Capital Budget and Operational Guidance

The Company currently has one drilling rig running in Oklahoma, with plans to add a second rig late in the first quarter. Drilling operations will commence mid year in the North Park Basin with one rig. 2017 capital expenditure guidance range is for $210-$220 million. Production and other operational guidance detail for the full year of 2017 can be found below.

Mid-Continent Assets in Oklahoma

•

Fourth quarter production of 4.0 MMBoe, (43.7 MBoepd, 23% oil, 24% NGLs, 53% natural gas)

•

Drilled six laterals in the fourth quarter, bringing six laterals online

•

Two Mississippian extended reach lateral wells (four total laterals), the Cherokee 1-2H/11 H and Cherokee 2-2H/11 H produced a combined 30-Day IP of 2,226 Boepd (49% oil), drilled and completed for $5.3 million ($1.3 million per lateral) – a new low cost record for the Company

•

2016 Mississippian drilling and completion costs averaged $1.7 million per lateral, a ~23% reduction versus 2015

The Company drilled the following three NW STACK laterals in 2016:

•

In the fourth quarter, SandRidge’s first Major County Meramec lateral, the Medill 1-27H, produced a 30-Day IP of 925 Boepd (77% oil), drilled and completed for $3.9 million

•

In the third quarter, SandRidge’s first Major County lower Osage lateral, the Keeton 1-24H, produced a 30-Day IP of 540 Boepd (46% oil), drilled and completed for $4.2 million

•

In the second quarter, the first Meramec horizontal lateral in Garfield County, the Charlene 1-29H, produced a 30-Day IP of 328 Boepd (54% oil), drilled and completed for $3.1 million

In 2016, SandRidge drilled 28 laterals, including 13 Mississippian laterals to sales, in the Mid-Continent with one rig. The Mississippian program consisted of 100% extended and multilaterals, providing a program IRR of 51% and achieving an average drilling and completion cost of $1.7 million per lateral, with the most recent two extended reach laterals averaging $1.3 million per lateral. Also in 2016, SandRidge continued development activities in the Oklahoma NW STACK play in Garfield and Major Counties.

Oklahoma NW STACK: Meramec and Osage

The STACK encompasses a geographic area initially developed in Oklahoma’s Canadian and Kingfisher Counties. Recently, industry activity expanded northwest into what is considered the NW STACK where SandRidge operates in Major, Woodward, and Garfield Counties with approximately 60,000 net acres prospective for the Meramec and Osage.

The STACK and NW STACK plays, while in different parts of the Anadarko Basin, share the same depositional history. As in the STACK, the NW STACK consists of Mississippian age rock with primary targets in the Meramec and Osage formations. The structure deepens from northeast to southwest, and in SandRidge’s Major, Woodward, and Garfield County areas, depth ranges from 5,800 to 12,500 feet true vertical depth (TVD), with the majority of acreage in the 6,000 to 9,000 feet TVD range. The Woodford Shale is the primary hydrocarbon source, while the organic content in the Meramec Shale provides a self-sourcing component as well. Similar to the STACK, there is an over-pressured area and normally pressured area in the NW STACK.

Since 2014, multiple operators (including SandRidge) have demonstrated encouraging initial well results in the NW STACK. The Company’s primary target in the NW STACK is the Meramec Shale, which consists of interbedded shales, sands and carbonates with thickness ranging from 50 to 160 feet. The Meramec production to date shows high oil content (greater than 40%), low water rates and total productivity consistent with an over-pressured reservoir. The Company’s secondary target, the Osage, is comprised of limestones and cherts, ranging from 450 to 1,300 feet in thickness. The Osage production is typically gassier than the Meramec with oil content greater than 20%. Significant industry activity in the NW STACK has established both the Meramec and Osage as productive reservoirs with successful wells throughout.

Subsequent to the fourth quarter, SandRidge acquired approximately 13,100 net acres (including approximately 700 Boepd of production) in Woodward County for $48 million in cash, expanding the Company’s three county (Major, Woodward, and Garfield) NW STACK acreage position to approximately 60,000 net acres. Approximately 27% of that position is currently held by production. Industry activity includes thirteen drilling rigs recently operating across the NW STACK with over 50 wells producing in the areas of interest. The Company’s recent success in the play, combined with competitor activity near SandRidge’s acreage supports focused Mid-Continent drilling activity, weighted towards Meramec and Osage targets in the NW STACK.

Niobrara Asset in North Park Basin, Jackson County, Colorado

•

Fourth quarter production of 181 MBo (2.0 MBopd), and full year production of 500 MBo

•

Completed and brought online three laterals during the fourth quarter including first extended reach lateral and first Niobrara “C” bench well

•

First Niobrara “C” bench well, the Hebron 4-18H, produced a 30-Day IP of 539 Boepd (92% oil)

•

First Niobrara two-mile extended reach lateral, the Castle 1-17H 20, produced a 30-Day IP of 901 Boepd (91% oil), drilled and completed for $6.8 million ($3.4 million per lateral – lowest cost per lateral to date)

•

North Park 3D seismic acquisition ongoing in Q1‘17

•

Planned core to include the Niobrara Shale, Carlile Shale and Frontier Sand in 2017. The associated pilot hole will log the entire stratigraphic section to investigate additional shallow zones such as the Sussex and Shannon formations.

During 2016, the Company drilled 11 laterals and tested various concepts, including Niobrara bench productivity, extended reach drilling, and the use of slickwater (versus crosslinked) frac fluid designs. The first five laterals (all one-mile laterals with crosslinked gel fracs) produced an average 30-Day IP of 478 Boepd (90% oil). The next three one-mile laterals (the Mutual 2-8H, Mutual 3-8H and Mutual 4-8H), tested various frac fluid

designs including slickwater. The resulting well performance was influenced by higher than anticipated water cut (greater than 70%), although total fluid production (oil plus water) showed similar to the five previous wells, stimulated with crosslink gel. The higher water cut was a result of pumping 30% more water than in the crosslinked gel jobs. The 30-Day IPs were below type curve expectations averaging 210 Boepd (91% oil) due to the high water cut. These wells are all responding favorably to artificial lift and are expected to achieve type curve EURs as the reservoir is dewatered.

In the fourth quarter, the Hebron 4-18H, the Company’s first Niobrara “C” bench well produced a 30-Day IP of 539 Boepd (92% oil), confirming development potential for multiple benches in the play. Also in the quarter, the Castle 1-17H 20 extended lateral well produced a 30-Day IP of 901 Boepd (91% oil). Both wells were completed with crosslinked stimulation.

The North Park Basin wells exhibit a relatively flat oil rate in the first several months of production due to the over-pressured nature of the Niobrara reservoir. The wells will free flow for two to three months at which point artificial lift is installed to further extend the plateau. In several instances, artificial lift was not installed early enough to maintain the plateau and production rates were temporarily reduced. The installation of artificial lift within the first few months of production will be the standard practice going forward.

Other Operational Activities

During the fourth quarter, Permian Central Basin Platform properties produced 143 MBoe (1.6 MBoepd, 82% oil, 11% NGLs, 7% natural gas). SandRidge continues to operate the Permian CBP assets and administrate the filing and distribution affairs on behalf of the Permian Royalty Trust.

Year End 2016 Estimated Proved Reserves

•

SEC proved reserves of 164 MMBoe with a PV-10 of $438 million (equal to the standardized measure)

•

NYMEX strip-based proved reserves of 184 MMBoe with a PV-10 of $946 million

•

74% of total proved reserves are proved developed

•

53% liquids (32% oil, an increase from 24% at year end 2015)

•

9 MMBoe (45% oil) reserve additions (extensions) from 2016 drilling program

•

Negative performance revisions were approximately 85% gas and associated NGLs and 15% oil

The Company’s total estimated SEC proved reserves as of December 31, 2016 were 164 MMBoe, comprised of 53% liquids (32% oil and 21% natural gas liquids) and 47% natural gas. Approximately 74% of the Company’s 2016 estimated proved reserves were classified as proved developed and 26% as proved undeveloped. The Company’s year end reserves reflect approximately 94.7 MMBoe of negative performance revisions for the year, which is approximately 85% or 79.9 MMBoe from changes to gas and NGL reserves and 15% or 14.8 MMBoe from changes to oil reserves. All of the Company’s estimated proved undeveloped reserves at December 31, 2016 are expected to be developed within the next five years. Utilizing SEC price guidelines, the PV-10 was $438.4 million (equal to the standardized measure due to the Company’s current tax position).

For comparative purposes, utilizing NYMEX forward closing prices for oil and natural gas on December 30, 2016 (the last trading day of 2016), total NYMEX strip-based proved reserves at December 31, 2016 were 184 MMBoe, with a PV-10 of $946 million, an increase of $508 million over the standardized measure and SEC PV-10. NYMEX strip-based proved reserves are calculated based on the SEC proved reserves estimation methodology, but applying NYMEX strip prices rather than SEC pricing. NYMEX strip-based PV-10 uses annual average prices for oil and natural gas shown in the NYMEX Strip Pricing table below.

Independent reserve engineering firms, Cawley, Gillespie & Associates, Inc. (Mid-Continent – Mississippian Lime), Ryder Scott Company, L.P. (North Park Basin—Niobrara) and Netherland, Sewell & Associates, Inc. (Permian Basin Trust properties – Grayburg/San Andres) engineered 94% of the Company’s year end 2016 proved reserves in accordance with SEC guidelines. SEC pricing used in the preparation of the December 31, 2016 reserves was $42.75 per Bbl for oil and $2.48 per MMBtu for natural gas, before adjustments.


	Oil MBbls			NGLs MBbls			Gas MMcf			Equivalent MBoe ⁽¹⁾			Standardized Measure / PV-10 $MM
Proved Reserves, December 31, 2015		77,911			61,075			1,113,840			324,626		$	1,315
Production		(5,529	)		(4,357	)		(56,895	)		(19,369	)
Sale of assets		(387	)		0			(145,267	)		(24,598	)
Change in accounting for Trusts		(6,971	)		(3,695	)		(50,508	)		(19,084	)
Performance Revisions		(14,796	)		(21,717	)		(349,244	)		(94,720	)
Pricing Revisions		(1,510	)		876			(68,865	)		(12,112	)
Extensions & Additions		4,166			1,425			21,720			9,210
Proved Reserves, December 31, 2016		52,884			33,607			464,782			163,955		$	438

(1)	Equivalent Boe are calculated using an energy equivalent ratio of six Mcf of natural gas to one Bbl of oil. Using an energy-equivalent ratio does not factor in price differences and energy-equivalent prices may differ significantly among produced products.

SEC Proved Reserves and NYMEX Strip-based Proved Reserves


	YE 2016@SEC Pricing ⁽¹⁾				YE 2016@NYMEX Strip Pricing ⁽²⁾
	Equivalent MBoe		Standardized measure / PV-10 $MM		Equivalent MBoe		PV-10 $MM
Developed		120,705	$	407		139,550	$	736
Undeveloped		43,250	$	31		44,700	$	210
Total Proved		163,955	$	438		184,250	$	946

(1)	SEC Pricing remains flat for reserve life at $42.75/Bo & $2.48/Mcf

(2)	NYMEX Strip pricing as of December 30, 2016, shown in table below


NYMEX Strip Pricing (as of 12/30/2016)
Year	Oil		Gas
2017	$	56.26	$	3.63
2018		56.54		3.14
2019		56.08		2.87
2020		56.05		2.88
2021		56.23		2.90
2022		56.57		2.93
2023+		57.98		3.46

Key Financial Results

Upon emergence from Chapter 11 reorganization, the Company elected to adopt fresh start accounting effective October 1, 2016, to coincide with the timing of its normal fourth quarter reporting. Under the principles of fresh start accounting, a new reporting entity was created, and, as a result, the Company allocated the reorganization value of the Company to its individual assets, including property, plant and equipment, based on their estimated fair values. Also, upon application of fresh start accounting, the Company made an accounting policy election to present transportation costs as a reduction from revenue. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the financial statements on or after October 1, 2016 will not be comparable with the financial statements prior to that date. References to the “Successor” refer to SandRidge subsequent to adoption of fresh start accounting. References to the “Predecessor” refer to SandRidge prior to adoption of fresh start accounting. Additionally, references to the “fourth quarter 2016” herein refer to operational activities, production, revenue, and production expenses of the Successor.

Fourth Quarter

•

Adjusted EBITDA was $71 million for fourth quarter 2016 compared to $79 million in fourth quarter 2015, pro forma for divestitures and net of Noncontrolling Interest

•

Adjusted operating cash flow of $52 million for fourth quarter 2016 compared to ($56) million in fourth quarter 2015

•

Adjusted net income of $29 million, or $0.86 per diluted share, for fourth quarter 2016 compared to adjusted net loss of $74 million in fourth quarter 2015

•

Incurred a non-cash ceiling test impairment charge of approximately $319 million resulting primarily from the application of fresh start accounting in which the full cost pool was determined based upon forward strip prices as of the Company’s Emergence date, where those prices were materially higher than prices utilized by SEC guidelines

Full Year

•

Adjusted EBITDA was $238 million in 2016 compared to $528 million in 2015, net of Noncontrolling Interest

•

Adjusted operating cash flow of ($9) million in 2016 compared to $246 million in 2015

•

Adjusted net loss of $64 million in 2016 compared to adjusted net loss of $135 million in 2015

Hedging

During and after the fourth quarter, SandRidge added oil and natural gas hedge positions in both 2017 and 2018. For the calendar year of 2017, the Company now has approximately 3.3 million barrels of oil hedged at an average WTI price of $52.24 as well as 32.9 billion cubic feet of natural gas hedged at an average price of $3.20 per MMBtu. For 2018, the Company has approximately 1.8 million barrels of oil hedged at an average WTI price of $55.34 as well as 3.7 billion cubic feet of natural gas hedged at an average price of $3.12.

Conference Call Information

The Company will host a conference call to discuss these results on Thursday, February 23, 2017 at 8:00 am CST. The telephone number to access the conference call from within the U.S. is (877) 201-0168 and from outside the U.S. is (647) 788-4901. The passcode for the call is 53513467. An audio replay of the call will be available from February 23, 2017 until 11:59 pm CDT on March 23, 2017. The number to access the conference call replay from within the U.S. is (800) 585-8367 and from outside the U.S. is (416) 621-4642. The passcode for the replay is 53513467.

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.

2017 Capital Expenditure and Operational Guidance


	Total Company
	Projection as of
	February 22, 2017
Production
Oil (MMBbls)		4.0 - 4.2
Natural Gas Liquids (MMBbls)		3.0 - 3.2

Total Liquids (MMBbls)		7.0 - 7.4
Natural Gas (Bcf)		42.0 - 43.5

Total (MMBoe)		14.0 - 14.7
Price Realization
Oil (differential below NYMEX WTI)		$2.75
Natural Gas Liquids (realized % of NYMEX WTI)		26%
Natural Gas (differential below NYMEX Henry Hub)		$1.00
Costs per Boe
LOE		$8.00 - $9.00
Adjusted G&A—Cash¹		$4.25 - $4.50
% of Revenue
Production Taxes		2.75% - 3.00%
Capital Expenditures ($ in millions)
Drilling and Completion
Mid-Continent		$65 - $70
North Park Basin		20 - 25
Other²		24

Total Drilling and Completion		$109 - $119
Other E&P
Land, G&G, and Seismic		$40
Infrastructure³		7
Workover		37
Capitalized G&A and Interest		15

Total Other Exploration and Production		$99
General Corporate		2

Total Capital Expenditures (excluding acquisitions and plugging and abandonment)		$210 - $220

Adjusted G&A - Cash is a non-GAAP financial measure as it excludes from G&A non-cash compensation, severance, bad debt allowance, and other non-recurring items. The most directly comparable GAAP measure for Adjusted G&A - cash is General and Administrative Expense. 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.

2)	2016 Carryover, Coring, and Non-Op

3)	Facilities - Electrical, SWD, Gathering, Pipeline ROW

2016 Actual Results vs. 2016 Capital Expenditure and Operational Guidance

The table below presents the actual results of the Company’s operations and capital expenditures for the full year of 2016 in comparison to its previous guidance, last provided on November 8, 2016.


	FY 2016 Actuals		FY 2016 Guidance (Midpoint)		Delta
Production
Oil (MMBbls)		5.5		5.5		—
Natural Gas Liquids (MMBbls)		4.4		4.2		0.2

Total Liquids (MMBbls)		9.9		9.7		0.2
Natural Gas (Bcf)		56.9		57.2		(0.3	)

Total (MMBoe)		19.4		19.2		0.2
Cost per Boe
LOE¹	$	7.98	$	8.90	$	(0.92	)
DD&A - Oil & Gas		6.23		6.00		0.23
DD&A - Other		1.64		1.43		0.21
Adj G&A - Cash	$	3.55	$	3.80	$	(0.25	)
Capital Expenditures ($ in Millions)
Drilling and Completion
Mid-Continent	$	42	$	45	$	(3	)
North Park Basin		57		58		(0	)
Other²		19		25		(6	)

Total Drilling and Completion	$	119	$	128	$	(9	)
Other E&P
Land, G&G, and Seismic	$	13	$	13	$	0
Infrastructure³		18		21		(3	)
Workovers		26		39		(13	)
Capitalized G&A and Interest		25		25		(1	)

Total Other Exploration and Production	$	81	$	98	$	(16	)
General Corporate	$	3	$	5	$	(2	)
Total Capital Expenditures (excluding acquisitions and plugging and abandonment)	$	202	$	230	$	(28	)

⁽¹⁾	One quarter of new accounting treatment for LOE

⁽²⁾	2015 Carryover, JV Penalty, Rig Penalty, Non-Op, SWD

⁽³⁾	Facilities – Electrical, SWD, Gathering, Pipelines

Operational and Financial Statistics

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


				Successor			Predecessor			Predecessor
	Combined Year Ended			Period from October 2, 2016 through			Period from January 1, 2016 through			Three Months Ended			Year Ended
	December 31, 2016			December 31, 2016			October 1, 2016			December 31, 2015
Production—Total
Oil (MBbl)		5,529			1,214			4,315			1,996			9,600
NGL (MBbl)		4,357			999			3,358			1,161			5,044
Natural gas (MMcf)		56,895			12,771			44,124			20,972			92,105
Oil equivalent (MBoe)		19,369			4,342			15,027			6,652			29,995
Daily production (MBoed)		52.9			47.2			54.8			72.3			82.2
Production—Mid-Continent
Oil (MBbl)		4,513			916			3,597			1,699			8,253
NGL (MBbl)		4,284			983			3,301			1,125			4,889
Natural gas (MMcf)		56,038			12,708			43,330			18,199			80,491
Oil equivalent (MBoe)		18,137			4,017			14,120			5,858			26,558
Daily production (MBoed)		49.6			43.7			51.5			63.7			72.8
Average price per unit
Realized oil price per barrel—as reported	$	39.09		$	47.03		$	36.85		$	39.27		$	45.83
Realized impact of derivatives per barrel		12.74			7.56			14.20			23.75			30.97

Net realized price per barrel	$	51.83		$	54.59		$	51.05		$	63.02		$	76.80

Realized NGL price per barrel—as reported	$	13.15		$	14.77		$	12.67		$	13.25		$	14.36
Realized impact of derivatives per barrel		—			—			—			—			—

Net realized price per barrel	$	13.15		$	14.77		$	12.67		$	13.25		$	14.36

Realized natural gas price per Mcf—as reported	$	1.84		$	2.07		$	1.78		$	1.82		$	2.12
Realized impact of derivatives per Mcf		(0.03	)		(0.11	)		(0.01	)		0.09			0.33

Net realized price per Mcf	$	1.81		$	1.96		$	1.77		$	1.91		$	2.45

Realized price per Boe—as reported	$	19.53		$	22.64		$	18.63		$	19.85		$	23.59

Net realized price per Boe—including impact of derivatives	$	23.08		$	24.41		$	22.70		$	27.23		$	34.51

Average cost per Boe
Lease operating⁽¹⁾	$	7.98		$	5.76		$	8.63		$	9.70		$	10.29
Production taxes		0.45			0.61			0.41			0.43			0.51
General and administrative
General and administrative, excluding stock-based compensation	$	6.11		$	3.01		$	7.00		$	5.74		$	4.40
Stock-based compensation		1.98			2.09			1.94			0.48			0.61

Total general and administrative	$	8.09		$	5.10		$	8.94		$	6.22		$	5.01
General and administrative—adjusted
General and administrative, excluding stock-based compensation ⁽²⁾	$	3.55		$	3.08		$	3.69		$	5.32		$	3.80
Stock-based compensation ⁽³⁾		0.70			0.67			0.71			0.40			0.43
Total general and administrative—adjusted	$	4.25		$	3.75		$	4.40		$	5.72		$	4.23

Depletion ⁽⁴⁾	$	6.56		$	8.31		$	6.05		$	8.14		$	10.81
Lease operating cost per Boe
Mid-Continent	$	6.95		$	4.70		$	7.58		$	7.36		$	7.66
Earnings per share
Earnings (loss) per share applicable to common stockholders
Basic				$	(17.61	)	$	2.01		$	(1.13	)	$	(7.16	)
Diluted				$	(17.61	)	$	2.01		$	(1.13	)	$	(7.16	)
Adjusted net income per share available to common stockholders
Basic				$	1.53		$	(0.13	)	$	(0.16	)	$	(0.35	)
Diluted				$	0.86		$	(0.13	)	$	(0.09	)	$	(0.21	)
Weighted average number of shares outstanding (in thousands)
Basic					18,967			708,928			586,801			521,936
Diluted ⁽⁵⁾					33,573			708,928			805,368			641,608

⁽¹⁾	In concert with an accounting policy election to present transportation costs as a reduction from revenue, the Company’s Lease Operating Expenses are now represented net of said transportation costs and therefore, presented lower than previous quarters

⁽²⁾

Excludes severance, doubtful receivable write-off (recovery) and restructuring costs totaling ($0.3) million and $49.8 million for the Successor and Predecessor 2016 periods, respectively. Excludes severance, legal settlements and shareholder litigation totaling $2.8 million and $17.8 million for the three-month period and year ended December 31, 2015, respectively.

⁽³⁾

Successor and Predecessor 2016 periods exclude $6.2 million and $18.5 million, respectively, for employee incentive and retention and the acceleration of certain stock awards. Three-month period and year ended December 31, 2015 exclude $0.6 million and $5.4 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.

Capital Expenditures

The table below summarizes the Company’s capital expenditures for 2016 and 2015 periods:


				Successor			Predecessor			Predecessor
	Combined Year Ended			Period from October 2, 2016 through			Period from January 1, 2016 through			Three Months Ended			Year Ended
	December 31, 2016			December 31, 2016			October 1, 2016			December 31, 2015
	(in thousands)
Drilling and production
Mid-Continent	$	97,057		$	17,212		$	79,845		$	80,557		$	592,346
Rockies		82,628			10,464			72,164			—			—
Other		(27	)		(92	)		65			1,457			5,714

		179,658			27,584			152,074			82,014			598,060
Leasehold and geophysical
Mid-Continent		6,135			8,906			(2,771	)		13,496			55,930
Rockies		3,089			1,728			1,361			—			—
Other		4,157			983			3,174			1,939			6,330

		13,381			11,617			1,764			15,435			62,260
Inventory		650			(1,139	)		1,789			(942	)		(4,298	)
Total exploration and development		193,689			38,062			155,627			96,507			656,022

Drilling and oil field services		23			—			23			1,900			4,632
Midstream		5,986			2,901			3,085			1,155			21,555
Other—general		2,755			83			2,672			999			19,406

Total capital expenditures, excluding acquisitions		202,453			41,046			161,407			100,561			701,615

Acquisitions		1,327			—			1,327			237,935			241,165

Total capital expenditures	$	203,780		$	41,046		$	162,734		$	338,496		$	942,780

Derivative Contracts

Subsequent to December 31, 2016, the Company entered into additional oil and gas swap contracts for the calendar years of 2017 and 2018.The table below sets forth the Company’s consolidated oil and natural gas price swaps and collars for 2017 as of February 22, 2017:


	Quarter Ending
	3/31/2017		6/30/2017		9/30/2017		12/31/2017		FY 2017
Oil (MMBbls):
Swap Volume		0.81		0.82		0.83		0.83		3.29
Swap	$	52.24	$	52.24	$	52.24	$	52.24	$	52.24
Natural Gas (Bcf):
Swap Volume		8.10		8.19		8.28		8.28		32.85
Swap	$	3.20	$	3.20	$	3.20	$	3.20	$	3.20

	3/31/2018		6/30/2018		9/30/2018		12/31/2018		FY 2018
Oil (MMBbls):
Swap Volume		0.45		0.46		0.46		0.46		1.83
Swap	$	55.34	$	55.34	$	55.34	$	55.34	$	55.34
Natural Gas (Bcf):
Swap Volume		0.90		0.91		0.92		0.92		3.65
Swap	$	3.12	$	3.12	$	3.12	$	3.12	$	3.12

Balance Sheet

The Company’s capital structure as of December 31, 2016 and 2015 is presented below.


	Successor			Predecessor
	December 31, 2016			December 31, 2015
	(in thousands)
Cash, cash equivalents and restricted cash	$	174,071		$	435,588

Successor
First lien facility	$	—		$	—
Building note		36,528			—
Mandatorily convertible 0% notes ⁽¹⁾		268,780			—
Predecessor
Senior credit facility					—
Senior Notes
8.75% Senior Secured Notes due 2020		—			1,265,814
Senior Unsecured Notes
8.75% Senior Notes due 2020, net		—			389,232
7.5% Senior Notes due 2021		—			751,087
8.125% Senior Notes due 2022		—			518,693
7.5% Senior Notes due 2023, net		—			534,869
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022, net		—			78,290
7.5% Convertible Senior Notes due 2023, net		—			24,393

Total debt		305,308			3,562,378
Stockholders’ equity (deficit)
Preferred stock (Predecessor)		—			6
Common stock ⁽¹⁾		20			630
Warrants (Successor)		88,381			—
Additional paid-in capital		758,498			5,299,886
Treasury stock, at cost		—			(5,742	)
Accumulated deficit		(333,982	)		(6,992,697	)

Total SandRidge Energy, Inc. stockholders’ equity (deficit)		512,917			(1,697,917	)

Noncontrolling interest		—			510,184
Total capitalization	$	818,225		$	2,374,645

⁽¹⁾	Mandatorily convertible 0% notes converted to approximately 14.1 million shares of Successor common stock in February 2016.

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(In thousands)


				Successor			Predecessor			Predecessor
	Combined Year Ended			Period from October 2, 2016 through			Period from January 1, 2016 through			Three Months Ended			Year Ended
	December 31, 2016			December 31, 2016			October 1, 2016			December 31, 2015
Revenues
Oil, natural gas and NGL	$	378,278		$	98,307		$	279,971		$	132,035		$	707,434
Other		13,987			149			13,838			11,607			61,275

Total revenues		392,265			98,456			293,809			143,642			768,709

Expenses
Production		154,605			24,997			129,608			64,543			308,701
Production taxes		8,750			2,643			6,107			2,892			15,440
Depreciation and depletion—oil and natural gas		120,584			33,971			86,613			53,007			319,913
Depreciation and amortization—other		25,245			3,922			21,323			10,148			47,382
Accretion of asset retirement obligations		6,455			2,090			4,365			1,154			4,477
Impairment		1,037,281			319,087			718,194			886,844			4,534,689
General and administrative		125,928			9,837			116,091			28,951			137,715
Employee termination benefits		30,690			12,334			18,356			12,451			12,451
Loss (gain) on derivative contracts		30,475			25,652			4,823			(14,027	)		(73,061	)
Loss on settlement of contract		90,184			—			90,184			50,976			50,976
Other operating expenses		4,616			268			4,348			6,109			52,704

Total expenses		1,634,813			434,801			1,200,012			1,103,048			5,411,387

Loss from operations		(1,242,548	)		(336,345	)		(906,203	)		(959,406	)		(4,642,678	)

Other (expense) income
Interest expense		(126,471	)		(372	)		(126,099	)		(107,852	)		(321,421	)
Gain on extinguishment of debt		41,179			—			41,179			282,498			641,131
Gain on reorganization items, net		2,430,599			—			2,430,599			—			—
Other income, net		4,076			2,744			1,332			832			2,040

Total other income		2,349,383			2,372			2,347,011			175,478			321,750

Income (loss) before income taxes		1,106,835			(333,973	)		1,440,808			(783,928	)		(4,320,928	)
Income tax expense		20			9			11			33			123

Net income (loss)		1,106,815			(333,982	)		1,440,797			(783,961	)		(4,321,051	)
Less: net loss attributable to noncontrolling interest		—			—			—			(130,263	)		(623,506	)

Net income (loss) attributable to SandRidge Energy, Inc.		1,106,815			(333,982	)		1,440,797			(653,698	)		(3,697,545	)
Preferred stock dividends		16,321			—			16,321			10,881			37,950

Income (loss) applicable to SandRidge Energy, Inc. common stockholders	$	1,090,494		$	(333,982	)	$	1,424,476		$	(664,579	)	$	(3,735,495	)

(Loss) earnings per share
Basic				$	(17.61	)	$	2.01		$	(1.13	)	$	(7.16	)

Diluted				$	(17.61	)	$	2.01		$	(1.13	)	$	(7.16	)

Weighted average number of common shares outstanding
Basic					18,967			708,928			586,801			521,936

Diluted					18,967			708,928			586,801			521,936

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(In thousands)


	Successor		Predecessor
	December 31,		December 31,
	2016		2015
Current assets	$	257,176	$	674,088
Total assets	$	1,081,392	$	2,922,027

Current liabilities	$	213,706	$	437,389
Total liabilities		568,475		4,109,760
Total liabilities and stockholders’ equity (deficit)	$	1,081,392	$	2,922,027

SandRidge Energy, Inc. and Subsidiaries

Condensed Consolidated Cash Flows

(In thousands)


				Successor			Predecessor
	Combined Year Ended December 31, 2016			Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015
Net cash (used in) provided by operating activities	$	(46,482	)	$	65,595		$	(112,077	)	$	373,537
Net cash used in investing activities		(207,525	)		(39,835	)		(167,690	)		(1,039,640	)
Net cash (used in) provided by financing activities		(7,510	)		(415,061	)		407,551			920,438

NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH		(261,517	)		(389,301	)		127,784			254,335
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of period		435,588			563,372			435,588			181,253

CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of period	$	174,071		$	174,071		$	563,372		$	435,588

Non-GAAP Financial Measures

Adjusted operating cash flow, adjusted EBITDA, pro forma adjusted EBITDA, adjusted net loss net debt and PV-10 of the Company’s proved reserves are non-GAAP financial measures.

The Company defines adjusted operating cash flow as net cash provided by (used in) operating activities before changes in operating assets and liabilities. It defines EBITDA as net loss before income tax 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, loss (gain) on derivative contracts net of cash received upon settlement of derivative contracts, loss on settlement of contract, loss (gain) on sale of assets, legal settlements, severance, oil field services – exit costs, gain on extinguishment of debt, restructuring costs, reorganization items and other various 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. Current net debt, as presented herein, is current long-term debt, less current cash and cash equivalents. PV-10, as presented herein, represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows. The PV-10 of the Company’s SEC proved reserves is calculated using 12-month average prices for the years ended December 31, 2016, 2015 and 2014. The PV-10 of the Company’s SEC proved reserves differs from standardized measure because it does not include the effects of income taxes on future net revenues. The PV-10 of the Company’s NYMEX strip-based proved reserves is calculated using NYMEX forward closing prices for oil and natural gas as of December 30, 2016. The PV-10 of the Company’s NYMEX strip-based reserves differs from standardized measure because it reflects the estimated proved reserves economically recoverable based on forward NYMEX strip prices rather than SEC pricing and does not include the effects of income taxes on future net revenues.

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 (loss), which excludes asset impairment, (loss) gain on derivative contracts net of cash received on settlement of derivative contracts, loss on settlement of contract, gain on sale of assets, severance, oil field services – exit costs, gain on extinguishment of debt, restructuring costs, reorganization items, employee incentive and retention and other non-cash items from 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 (loss) is not a measure of financial performance under GAAP and should not be considered a substitute for loss applicable to common stockholders.

The Company also uses the term net debt to determine the extent to which the Company’s outstanding debt obligations would be satisfied by its cash and cash equivalents on hand. Management believes this metric is useful to investors in determining the Company’s current leverage position following recent significant events subsequent to the period.

PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities. It is useful because its calculation is not dependent on the taxpaying status of the entity. The Company believes the PV-10 of SEC reserves is an important financial measure used by investors and the industry to compare a company’s reserves to those of its

peers without the effects of tax characteristics which can differ among comparable companies. The Company believes the PV-10 of NYMEX strip-based reserves is useful to investors to illustrate the potential value of proved reserves that are economically recoverable in the current commodity price environment rather than SEC prices. Neither the PV-10 of the Company’s SEC reserves, the PV-10 of its NYMEX strip-based reserves nor the Standardized Measure represents an estimate of fair market value of the Company’s oil and natural gas properties.

The tables below reconcile the most directly comparable GAAP financial measures to operating cash flow, EBITDA, adjusted EBITDA, adjusted net loss and PV-10 of proved reserves.

Reconciliation of Cash (Used in) Provided by Operating Activities to Adjusted Operating Cash Flow


				Successor			Predecessor			Predecessor
	Combined Year Ended			Period from October 2, 2016 through			Period from January 1, 2016 through			Three Months Ended			Year Ended
	December 31, 2016			December 31, 2016			October 1, 2016			December 31, 2015
	(in thousands)
Net cash (used in) provided by operating activities	$	(46,482	)	$	65,595		$	(112,077	)	$	12,651		$	373,537
Changes in operating assets and liabilities		37,759			(13,437	)		51,196			(68,466	)		(127,550	)

Adjusted operating cash flow	$	(8,723	)	$	52,158		$	(60,881	)	$	(55,815	)	$	245,987

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


				Successor			Predecessor			Predecessor
	Combined Year Ended			Period from October 2, 2016 through			Period from January 1, 2016 through			Three Months Ended			Year Ended
	December 31, 2016			December 31, 2016			October 1, 2016			December 31, 2015
	(in thousands)
Net income (loss)	$	1,106,815		$	(333,982	)	$	1,440,797		$	(653,698	)	$	(3,697,545	)
Adjusted for
Income tax expense		20			9			11			33			123
Interest expense		129,107			1,590			127,517			108,303			322,502
Depreciation and amortization—other		25,245			3,922			21,323			10,148			47,382
Depreciation and depletion—oil and natural gas		120,584			33,971			86,613			53,007			319,913
Accretion of asset retirement obligations		6,455			2,090			4,365			1,154			4,477

EBITDA		1,388,226			(292,400	)		1,680,626			(481,053	)		(3,003,148	)
Asset impairment		1,037,281			319,087			718,194			886,844			4,534,689
Interest income		(2,636	)		(1,218	)		(1,418	)		(451	)		(1,081	)
Stock-based compensation		6,257			1,966			4,291			2,171			11,465
Loss (gain) on derivative contracts		30,475			25,652			4,823			(14,027	)		(73,061	)
Cash received upon settlement of derivative contracts ⁽¹⁾		80,306			13,455			66,851			49,123			327,702
Loss on settlement of contract		90,184			—			90,184			50,976			50,976
(Gain) loss on sale of assets		(2,481	)		313			(2,794	)		(606	)		1,491
Severance		29,875			12,334			17,541			(115	)		11,704
Oil field services—exit costs		2,428			—			2,428			83			4,436
Gain on extinguishment of debt		(41,179	)		—			(41,179	)		(282,498	)		(641,131	)
Restructuring costs		23,669			4,804			18,865			—			—
Gain on reorganization items, net		(2,430,599	)		—			(2,430,599	)		—			—
Employee incentive and retention		22,984			2,843			20,141			—			—
Other		3,277			(15,755	)		19,032			3,062			11,732
Non-cash portion of noncontrolling interest ⁽²⁾		—			—			—			(146,268	)		(708,238	)

Adjusted EBITDA	$	238,067		$	71,081		$	166,986		$	67,241		$	527,536

Less: EBITDA attributable to WTO properties (2016)		1,990			—			1,990			11,932			61,434

Pro forma adjusted EBITDA	$	240,057		$	71,081		$	168,976		$	79,173		$	588,970

⁽¹⁾	Excludes amounts received upon early settlement of contracts for 2016 period.

⁽²⁾	Represents depreciation and depletion, impairment, gain on commodity derivative contracts net of cash received on settlement and income tax expense attributable to noncontrolling interests in the 2015 period.

Reconciliation of Cash (Used in) Provided by Operating Activities to Adjusted EBITDA


				Successor			Predecessor			Predecessor
	Combined Year Ended			Period from October 2, 2016 through			Period from January 1, 2016 through			Three Months Ended			Year Ended
	December 31, 2016			December 31, 2016			October 1, 2016			December 31, 2015
	(in thousands)
Net cash (used in) provided by operating activities	$	(46,482	)	$	65,595		$	(112,077	)	$	12,651		$	373,537
Changes in operating assets and liabilities		37,759			(13,437	)		51,196			(68,466	)		(127,550	)
Interest expense		129,107			1,590			127,517			108,303			322,502
Cash received on early settlement of derivative contracts		(17,894	)		—			(17,894	)		—			—
Contractual maturity reached on previous early settlements		17,893			5,756			12,137			—			—
Cash paid on early conversion of convertible notes		33,452			—			33,452			30,033			32,741
Cash paid on settlement of contract		11,000			—			11,000			24,889			24,889
Gain (loss) on convertible notes derivative liability		1,324			—			1,324			(20,523	)		(10,377	)
Severance ⁽¹⁾		20,511			8,048			12,463			(687	)		6,317
Oil field services—exit costs ⁽¹⁾		2,386			—			2,386			63			4,338
Restructuring costs		23,669			4,804			18,865			—			—
Cash paid for reorganization items		12,483			—			12,483			—			—
Employee incentive and retention		22,984			2,843			20,141			—			—
Noncontrolling interest—SDT ⁽²⁾		—			—			—			(6,760	)		(25,997	)
Noncontrolling interest—SDR ⁽²⁾		—			—			—			(4,216	)		(20,493	)
Noncontrolling interest—PER ⁽²⁾		—			—			—			(5,028	)		(38,240	)
Other		(10,125	)		(4,118	)		(6,007	)		(3,018	)		(14,131	)

Adjusted EBITDA	$	238,067		$	71,081		$	166,986		$	67,241		$	527,536

⁽¹⁾	Excludes associated stock-based compensation.

⁽²⁾	Excludes depreciation and depletion, impairment, gain on commodity derivative contracts net of cash received on settlement and income tax expense attributable to noncontrolling interests for 2015 period.

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


				Successor			Predecessor			Predecessor
	Combined Year Ended			Period from October 2, 2016 through			Period from January 1, 2016 through			Three Months Ended			Year Ended
	December 31, 2016			December 31, 2016			October 1, 2016			December 31, 2015
	(in thousands)
Income available (loss applicable) to common stockholders	$	1,090,494		$	(333,982	)	$	1,424,476		$	(664,579	)	$	(3,735,495	)
Asset impairment ⁽¹⁾		1,037,281			319,087			718,194			751,120			3,878,804
Loss (gain) on derivative contracts ⁽¹⁾		30,475			25,652			4,823			(13,485	)		(67,411	)
Cash received upon settlement of derivative contracts ⁽¹⁾⁽²⁾		80,306			13,455			66,851			41,540			291,203
(Gain) loss on convertible notes derivative liability		(1,324	)		—			(1,324	)		20,523			10,377
Loss on settlement of contract		90,184			—			90,184			50,976			50,976
(Gain) loss on sale of assets		(2,481	)		313			(2,794	)		(606	)		1,491
Severance		29,875			12,334			17,541			(115	)		11,704
Oil field services—exit costs		2,428			—			2,428			83			4,436
Gain on extinguishment of debt		(41,179	)		—			(41,179	)		(282,498	)		(641,131	)
Restructuring costs		23,669			4,804			18,865			—			—
Gain on reorganization items, net		(2,430,599	)		—			(2,430,599	)		—			—
Employee incentive and retention		22,984			2,843			20,141			—			—
Other		4,024			(15,494	)		19,518			3,484			10,381
Effect of income taxes		22			10			12			24			101

Adjusted net (loss) income applicable to common stockholders		(63,841	)		29,022			(92,863	)		(93,533	)		(184,564	)
Preferred stock dividends ⁽³⁾		—			—			—			10,881			37,950
Effect of convertible debt, net of income taxes ⁽³⁾		—			—			—			9,151			11,707

Total adjusted net (loss) income	$	(63,841	)	$	29,022		$	(92,863	)	$	(73,501	)	$	(134,907	)

Weighted average number of common shares outstanding
Basic					18,967			708,928			586,801			521,936
Diluted					33,573			708,928			805,368			641,608
Total adjusted net income (loss)
Per share—basic				$	1.53		$	(0.13	)	$	(0.16	)	$	(0.35	)

Per share—diluted				$	0.86		$	(0.13	)	$	(0.09	)	$	(0.21	)

⁽¹⁾	Excludes amounts attributable to noncontrolling interests for 2015 period.

⁽²⁾	Excludes amounts received for early settlement of contracts for 2016 period.

⁽³⁾	Not considered dilutive securities in 2016 periods.

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


	Successor		Predecessor
	December 31, 2016		December 31, 2015
	(in millions)
Standarized measure of discounted net cash flows⁽¹⁾	$	438	$	1,314
Present value of future net income tax expense discounted at 10%		—		1

PV-10⁽²⁾	$	438	$	1,315

Effects of calculating reserves and pricing using strip pricing		508
PV-10 of strip-based proved reserves	$	946

⁽¹⁾	Includes approximately $225 million attributable to SandRidge noncontrolling interests at December 31, 2015.

⁽²⁾	Includes approximately $226 million attributable to SandRidge noncontrolling interests at December 31, 2015.

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 the Company’s corporate strategies, future operations, drilling plans, oil, and natural gas and natural gas liquids production, price realizations and differentials, reserves, operating, general and administrative and other costs, capital expenditures, tax rates, infrastructure investment, and 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 Part I, Item 1A - “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2015 and in comparable “Risk Factor” sections of our Quarterly Reports on Form 10-Q filed after such form 10-K. 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. (NYSE: SD) is an oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma with its principal focus on developing high-return, growth-oriented projects in the U.S. Mid-Continent and Niobrara Shale.

SANDRIDGE ENERGY INC - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - February 22, 2017

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