EX-99.1

EX-99.1 2 d481781dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

SandRidge Energy, Inc. Reports Financial and Operational Results for Third Quarter of 2017

Oklahoma City, Oklahoma, November 1, 2017 – SandRidge Energy, Inc. (the “Company” or “SandRidge”) (NYSE:SD) today announced financial and operational results for the quarter ended September 30, 2017. Additionally, the Company will host a conference call to discuss these results on November 2, at 8:00 a.m. CT (833-245-9650, International: 647-689-4222 – passcode: 94553818). Presentation slides will be available on the Company’s website, www.sandridgeenergy.com, under Investor Relations/Events.

Operational Results and Activity

Production for the third quarter was 3.6 MMBoe (27% oil, 23% NGLs and 50% natural gas). The Company’s Mid-Continent assets produced approximately 93% of total production, with its North Park Basin and Permian assets making up the balance. As more NW STACK and North Park wells are brought to sales, oil is expected to become a larger percentage of total production. During the quarter, the Company averaged two rigs in the NW STACK targeting the Meramec and one rig targeting multiple benches of the Niobrara in the North Park Basin.

Financial Results

The Company reported a net loss of $8 million, or $0.25 per share, and net cash provided by operating activities of $44 million for the third quarter of 2017. 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 $12 million, or $0.35 per share, and “operating cash flow” totaled $46 million. Earnings before interest, income taxes, depreciation, depletion, and amortization, adjusted for certain other items, otherwise referred to as “adjusted EBITDA,” for the third quarter was $42 million.⁽¹⁾

James Bennett, SandRidge President and CEO said, “As we near the end of the year, we remain committed to our strategy of balance sheet preservation and cost reduction while prudently developing our assets. In Oklahoma’s NW STACK, successful Meramec drilling above horizontal Osage production demonstrates stacked pay and supports future development of the deeper Osage zone. In Colorado’s North Park Basin, recent drilling confirms production from all four Niobrara benches (A, B, C and D), proving additional zones and increasing our future drilling inventory. Our previously announced Drilling Participation Agreement will fund continued delineation of the NW STACK, allowing for capital reallocation toward a growing opportunity set in the North Park Basin. Ongoing success with our cost reduction initiatives is reflected in our updated LOE and G&A guidance, which reduces cash costs another $7 million this year. As we prepare our 2018 budget, our undivided focus will be directed toward returns on capital and resource value creation, supported by our strategic emphasis on oil-weighted development.”

Highlights During and Subsequent to the Third Quarter

Confirmed All Four North Park Basin Niobrara Benches (A, B, C and D) Productive

Achieved $0.5 Million D&C Capital Reduction on North Park Niobrara Two-Mile XRLs

Spud Initial Wells Under NW STACK Drilling Participation Agreement

Confirmed Meramec/Osage Stacked Pay in NW STACK Spacing Test

The Company has defined and reconciled certain non-GAAP financial measures including adjusted net income, operating cash flow, adjusted EBITDA, adjusted G&A per Boe 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 14.

Drilled First SandRidge NW STACK Well in Dewey County, Oklahoma

Lowered Lease Operating Expense Guidance to $6.90-$7.25 from $7.00-$7.50

Lowered Adjusted G&A per Boe Guidance to $4.00-$4.20 from $4.25-$4.50

Net Loss of $8 Million and Adjusted Net Income of $12 Million

Adjusted EBITDA of $42 Million

Capital Expenditures of $71 Million

Production of 3.6 MMBoe (27% Oil, 23% NGLs and 50% Natural Gas)

$515 Million of Liquidity Including $98 Million of Cash and $417 Million Capacity Under Credit Facility (Net of Letters of Credit)

Confirmed $425 Million Borrowing Base Under Credit Facility

Updated 2017 Operational Guidance

The Company is updating its operational guidance to reflect cost savings related to lease operating expense and G&A reduction initiatives. These savings reflect the removal of approximately $7 million from the Company’s current cost structure, at the midpoint of guidance.

More information regarding operational guidance updates and capital budget details can be found below on page 6 of this release.

Mid-Continent Assets in Oklahoma

•

Third quarter production of 3.3 MMBoe (36.0 MBoepd, 22% oil, 24% NGLs, 54% natural gas)

•

Drilled first SandRidge Dewey County Meramec well with a 30-Day IP of 598 Boepd (71% oil)

•

Confirmed Meramec/Osage stacked pay with Meramec well producing a 30-Day IP of 397 Boepd (88% oil)

•

Spud initial wells under NW STACK Drilling Participation Agreement

•

Averaged two rigs targeting the Meramec during the quarter

•

Drilled seven SRLs and two XRLs during the quarter and brought two SRLs and three XRLs online

NW STACK Highlights and Developments

NW STACK highlights from the third quarter include extension of Meramec production south into Dewey County and the confirmation of stacked pay. The Regina 1915 1-18H SRL is the Company’s first Meramec well drilled in Dewey County, Oklahoma. Producing a 30-Day IP of 598 Boepd (71% oil), this well extends the Company’s production and resource potential beyond Major, Woodward and Garfield counties. In Major County, the Company confirmed Meramec/Osage stacked pay by drilling a Meramec well above existing horizontal Osage production. The Audra Claire 2015 1-24H, producing a 30-Day IP of 397 Boepd (88% oil) from the Meramec, supports stacked pay potential in the NW STACK. As part of the Company’s strategy to initially develop the Meramec, this spacing test supports future development of the Osage.

During the fourth quarter, the Company will spend approximately $15 million completing wells drilled in the third quarter and running two rigs under the Drilling Participation Agreement. The two rigs will continue to drill SRLs and XRLs targeting the Meramec where drilling and completion costs are $4.4 million and $6.5 million, respectively.

NW STACK Drilling Participation Agreement

As previously announced, the Company executed a $200 million development agreement (the “Drilling Participation Agreement”) with a private investment fund (“Counterparty”) to develop SandRidge Meramec operated wells in dedicated sections, primarily in Major and Woodward Counties. Under the Drilling Participation Agreement, the Counterparty will fund an initial $100 million tranche for its share of drilling and completion costs, receiving a wellbore-only working interest subject to reversionary hurdles.

Development Costs and Working Interest (WI) Structure


	Counterparty		SandRidge
Development Costs		90% of Costs		10% of Costs
Initial Working Interest		80% of WI		20% of WI
Reversion If Counterparty Achieves 10% IRR		35% of WI		65% of WI
Reversion If Counterparty Achieves 15% IRR		11% of WI		89% of WI

The Company initiated the first wells under the Drilling Participation Agreement during the quarter and will continue running two rigs under its terms. Designated as operator, the Company is responsible for the selection, location and scheduling of wells drilled. Following the initial tranche of wells and funding, a second $100 million tranche will be available subject to mutual agreement.

Niobrara Asset in North Park Basin, Jackson County, Colorado

•

Third quarter oil production of 128 MBo (1.4 MBopd)

•

Confirmed all four North Park Basin Niobrara benches (A, B, C, and D) productive

•

Achieved Niobrara XRL D&C capital reduction of $0.5 million due to pad drilling

•

One rig targeting the Niobrara during the quarter

•

Drilled three XRLs and brought two XRLs online during the quarter

During the quarter, the Company completed and brought online two XRLs, the Grizzly 2-1H36 and Grizzly 4-1H36, which are currently flowing back. These wells established oil production in the Niobrara A and B benches, confirming all four Niobrara benches (A, B, C and D) productive which expands the Company’s oil resource value.

In addition to growing its inventory, the Company has continued to capture efficiencies in the North Park Basin. The Grizzly wells were each drilled in 12 days, surpassing cycle time expectations by 20%. Furthermore, four additional XRLs were drilled in less than 14 days each as part of a recent 80 acre spacing test. These cycle time achievements and numerous other pad drilling efficiencies have successfully led to reduced drilling and completion costs of $6.7 million, compared to $7.2 million where full rig mobilization is required.

During the fourth quarter, the Company will spend approximately $34 million of capital completing wells drilled in the third quarter and running one rig drilling Niobrara XRLs. The Company’s 2017 drilling program will hold over 105,000 acres by production or federal unit, which represents 85% of its current 123,000 net acre position. Lastly, $13 million will be invested to construct central tank batteries and infrastructure in support of production brought online this year and into 2018.

Other Operational Activities

During the third quarter, Permian Central Basin Platform properties produced 127 MBoe (1.4 MBoepd, 80% oil, 13% NGLs, 7% natural gas).

Key Financial Highlights and Results

Third Quarter Results

•

Net loss of $8 million, or $0.25 per share, for third quarter 2017 compared to a $404 million loss, or $0.56 per share, in third quarter of 2016

•

Adjusted net income of $12 million, or $0.35 per diluted share, for third quarter 2017 compared to adjusted net income of $25 million, or $0.04 per diluted share, in third quarter 2016

•

Adjusted EBITDA was $42 million for third quarter 2017 compared to $65 million in third quarter 2016

•

Net cash provided by operating activities of $44 million for third quarter of 2017 compared to $75 million for third quarter of 2016

•

Operating cash flow of $46 million for third quarter 2017 compared to $32 million in third quarter 2016

First Nine Months of 2017

•

Net Income of $66 million, or $2.06 per diluted share, for the first nine months of 2017 compared to a $1.2 billion loss, or $1.76 per share, for the first nine months of 2016

•

Adjusted net income of $41 million, or $1.27 per diluted share, for the first nine months of 2017 compared to an adjusted net loss of $93 million, or $0.13 per share, for the first nine months of 2016

•

Adjusted EBITDA was $144 million for the first nine months of 2017 compared to $167 million for the first nine months of 2016

•

Net cash provided by operating activities of $148 million for the first nine months of 2017 compared to $64 million used in the first nine months of 2016

•

Operating cash flow of $142 million for the first nine months of 2017 compared to negative $60 million for the first nine months of 2016

Capitalization & Liquidity

•

35.6 million shares outstanding

•

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

•

Liquidity of $515 million including $98 million of cash and $417 million capacity under the credit facility, net of outstanding letters of credit

•

Outstanding debt consists of a $38 million note secured by the Company’s real estate, resulting in zero net debt

Hedging

In 2017, the Company 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. 2017 oil hedges represent 78% of the midpoint of current oil volume guidance. 2017 gas hedges represent 77% of the midpoint of current gas volume guidance.

For 2018, the Company has approximately 2.4 million barrels of oil hedged at an average WTI price of $54.59 as well as 17.3 billion cubic feet of natural gas hedged at an average price of $3.16 per MMBtu.

Conference Call Information

The Company will host a conference call to discuss these results on Thursday, November 2, 2017 at 8:00 am CT. The telephone number to access the conference call from within the U.S. is (833) 245-9650 and from outside the U.S. is (647) 689-4222. The passcode for the call is 94553818. An audio replay of the call will be available from November 2, 2017 until 11:59 pm CT on December 2, 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 94553818.

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 Operational and Capital Expenditure Guidance

The table below highlights reductions to the Company’s lease operating expense and adjusted G&A guidance as well as raised production severance tax guidance.

Additional 2017 Guidance detail is available on the Company’s website, www.sandridgeenergy.com, under Investor Relations/Financial Information/Guidance.


	Updated			Previous
	Guidance			Guidance
	Projection as of			Projection as of
	November 1, 2017			August 2, 2017
Production
Oil (MMBbls)		4.1 - 4.3			4.1 - 4.3
Natural Gas Liquids (MMBbls)		3.1 - 3.3			3.1 - 3.3

Total Liquids (MMBbls)		7.2 - 7.6			7.2 - 7.6
Natural Gas (Bcf)		42.0 - 43.5			42.0 - 43.5

Total (MMBoe)		14.2 - 14.9			14.2 - 14.9

Price Realization
Oil (differential below NYMEX WTI)	$	2.75		$	2.75
Natural Gas Liquids (realized % of NYMEX WTI)		33	%		28	%
Natural Gas (differential below NYMEX Henry Hub)	$	1.00		$	1.00

Costs per Boe
LOE	$	*6.90 - $7.25*		$	7.00 - $7.50
Adjusted G&A¹	$	*4.00 - $4.20*		$	4.25 - $4.50

% of Revenue
Production Taxes		*3.50% - 3.75*	%		3.00% - 3.25	%

Capital Expenditures ($ in millions)

Drilling and Completion
Mid-Continent	$	60 - $65		$	60 - $65
North Park Basin		60 - 65			60 - 65
Other²		20			20

Total Drilling and Completion	$	140 - $150		$	140 - $150

Other E&P
Land, G&G, and Seismic	$	46		$	46
Infrastructure³		18			18
Workover		30			30
Capitalized G&A and Interest		14			14

Total Other Exploration and Production	$	108		$	108

General Corporate		2			2

Total Capital Expenditures (excluding acquisitions and plugging and abandonment)	$	250 - $260		$	250 - $260

Adjusted G&A per Boe is a non-GAAP financial measure. The Company has defined this measure at the conclusion of this press release under the “Non-GAAP Financial Measures” beginning on page 14. 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, Non-Op and SWD

3)	Infrastructure - Production facilities, Pipeline ROW and Electrical

Operational and Financial Statistics

Upon emergence from Chapter 11 reorganization, the Company elected to adopt fresh start accounting effective October 1, 2016. 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.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	Successor			Predecessor			Successor			Predecessor
	2017			2016			2017			2016
Production - Total
Oil (MBbl)		954			1,282			3,130			4,315
NGL (MBbl)		807			1,103			2,601			3,358
Natural gas (MMcf)		10,850			13,079			33,883			44,124
Oil equivalent (MBoe)		3,569			4,565			11,378			15,027
Daily production (MBoed)		38.8			49.6			41.7			54.8

Average price per unit
Realized oil price per barrel - as reported	$	46.16		$	42.82		$	47.22		$	36.85
Realized impact of derivatives per barrel		3.51			10.93			2.20			14.20

Net realized price per barrel	$	49.67		$	53.75		$	49.42		$	51.05

Realized NGL price per barrel - as reported	$	19.07		$	13.90		$	16.52		$	12.67
Realized impact of derivatives per barrel		—			—			—			—

Net realized price per barrel	$	19.07		$	13.90		$	16.52		$	12.67

Realized natural gas price per Mcf - as reported	$	1.95		$	2.27		$	2.14		$	1.78
Realized impact of derivatives per Mcf		0.15			0.05			0.02			(0.01	)

Net realized price per Mcf	$	2.10		$	2.32		$	2.16		$	1.77

Realized price per Boe - as reported	$	22.57		$	21.89		$	23.14		$	18.63

Net realized price per Boe - including impact of derivatives	$	23.97		$	25.10		$	23.81		$	22.70

Average cost per Boe
Lease operating⁽¹⁾	$	7.50		$	8.68		$	6.77		$	8.63
Production taxes	$	1.01		$	0.50		$	0.83		$	0.41

General and administrative	$	5.69		$	6.38		$	5.62		$	8.95
Less non-recurring items ⁽²⁾		(0.96	)		(0.11	)		(0.85	)		(3.31	)
Less stock-based compensation		(0.83	)		(2.39	)		(1.10	)		(1.95	)

Adjusted G&A	$	3.90		$	3.88		$	3.67		$	3.69

Depletion ⁽³⁾	$	8.69		$	6.07		$	7.69		$	6.05

Earnings per share
(Loss) earnings per share applicable to common stockholders
Basic	$	(0.25	)	$	(0.56	)	$	2.07		$	(1.76	)
Diluted	$	(0.25	)	$	(0.56	)	$	2.06		$	(1.76	)

Adjusted net income (loss) per share available to common stockholders
Basic	$	0.35		$	0.04		$	1.28		$	(0.13	)
Diluted	$	0.35		$	0.04		$	1.27		$	(0.13	)

Weighted average number of shares outstanding (in thousands)
Basic		34,290			718,373			31,750			708,788
Diluted ⁽⁴⁾		34,388			718,373			31,984			708,788

⁽¹⁾	Transportation costs are presented as a reduction of revenue by the Successor Company compared to the Predecessor Company’s presentation of these costs as lease operating expenses.

⁽²⁾

Adjusted G&A per Boe is a non-GAAP financial measure. The Company has defined this measure at the conclusion of this press release under the “Non-GAAP Financial Measures” beginning on page 14. Excludes restructuring costs and drilling participating agreement transaction costs totaling $3.4 million and $9.6 million for the three and nine-month periods ended September 30, 2017. Excludes restructuring costs and various other insignificant costs totaling $0.5 million and $33.1 million for the three and nine-month periods ended September 30, 2016, respectively. The nine-month period ended September 30, 2016 additionally excludes a $16.7 million doubtful receivable write-off.

⁽³⁾	Includes accretion of asset retirement obligation.

⁽⁴⁾	Includes shares considered antidilutive for calculating loss per share in accordance with GAAP.

Capital Expenditures

The table below presents actual results of the Company’s capital expenditures for the three and nine-month periods ended September 30, 2017 at the same level of detail as its full year capital expenditure guidance.


	Three Months Ended		Nine Months Ended
	September 30, 2017		September 30, 2017
	(in thousands)		(in thousands)
Drilling and Completion
Mid-Continent	$	20,686	$	47,647
North Park Basin		19,468		24,782
Other¹		5,799		18,375

Total Drilling and Completion	$	45,954	$	90,804

Other E&P
Land, G&G, and Seismic	$	10,109	$	39,915
Infrastructure²		3,072		4,789
Workovers		8,285		21,667
Capitalized G&A and Interest		3,315		9,402

Total Other Exploration and Production	$	24,782	$	75,774

General Corporate	$	4	$	1,406

Total Capital Expenditures (excluding acquisitions and plugging and abandonment)	$	70,740	$	167,984

1)	2016 Carryover, Coring, Non-Op and SWD

2)	Infrastructure - Production facilities, Pipeline ROW and Electrical

Derivative Contracts

The table below sets forth the Company’s consolidated oil and natural gas price swaps for 2017 and 2018 as of October 27, 2017:


	Quarter Ending
	3/31/2017		6/30/2017		9/30/2017		12/31/2017		FY 2017
Oil Swaps:
Total Volume (MMBbls)		0.81		0.82		0.83		0.83		3.29
Daily Volume (MBblspd)		9.0		9.0		9.0		9.0		9.0
Swap Price ($/bbl)	$	52.24	$	52.24	$	52.24	$	52.24	$	52.24

Natural Gas Swaps:
Total Volume (Bcf)		8.10		8.19		8.28		8.28		32.85
Daily Volume (MMBtupd)		90.0		90.0		90.0		90.0		90.0
Swap Price ($/MMBtu)	$	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 Swaps:
Total Volume (MMBbls)		0.63		0.64		0.55		0.55		2.37
Daily Volume (MBblspd)		7.0		7.0		6.0		6.0		6.5
Swap Price ($/bbl)	$	54.27	$	54.27	$	54.97	$	54.97	$	54.59

Natural Gas Swaps:
Total Volume (Bcf)		6.30		3.64		3.68		3.68		17.30
Daily Volume (MMBtupd)		70.0		40.0		40.0		40.0		47.4
Swap Price ($/MMBtu)	$	3.24	$	3.11	$	3.11	$	3.11	$	3.16

Capitalization

The Company’s capital structure as of September 30, 2017 and December 31, 2016 is presented below:


	September 30,			December 31,
	2017			2016
	(In thousands)
Cash, cash equivalents and restricted cash	$	135,513		$	174,071

Credit facility	$	—		$	—
Building note		37,601			36,528
Mandatorily convertible 0% notes		—			268,780

Total debt		37,601			305,308

Stockholders’ equity
Common stock		36			20
Warrants		88,475			88,381
Additional paid-in capital		1,037,932			758,498
Accumulated deficit		(268,160	)		(333,982	)

Total SandRidge Energy, Inc. stockholders’ equity		858,283			512,917

Total capitalization	$	895,884		$	818,225

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

(In thousands, except per share amounts)


	Three Months Ended September 30,						Nine Months Ended September 30,
	Successor			Predecessor			Successor			Predecessor
	2017			2016			2017			2016
Revenues
Oil, natural gas and NGL	$	80,540		$	99,934		$	263,235		$	279,971
Other		352			4,122			858			13,838

Total revenues		80,892			104,056			264,093			293,809

Expenses
Production		26,765			39,640			76,997			129,608
Production taxes		3,606			2,278			9,435			6,107
Depreciation and depletion - oil and natural gas		31,029			27,725			87,486			90,978
Depreciation and amortization - other		3,399			7,514			10,729			21,323
Impairment		498			354,451			3,475			718,194
General and administrative		20,292			29,145			63,999			134,447
Loss (gain) on derivative contracts		11,702			(338	)		(46,024	)		4,823
Loss on settlement of contract		—			—			—			90,184
Other operating (income) expense		(132	)		979			135			4,348

Total expenses		97,159			461,394			206,232			1,200,012

(Loss) income from operations		(16,267	)		(357,338	)		57,861			(906,203	)

Other (expense) income
Interest expense, net		(872	)		(3,343	)		(2,757	)		(126,099	)
Gain on extinguishment of debt		—			—			—			41,179
Reorganization items, net		—			(42,754	)		—			(243,672	)
Other income (expense), net		197			(898	)		2,222			1,332

Total other expense		(675	)		(46,995	)		(535	)		(327,260	)

(Loss) income before income taxes		(16,942	)		(404,333	)		57,326			(1,233,463	)
Income tax (benefit) expense		(8,457	)		4			(8,496	)		11

Net (loss) income		(8,485	)		(404,337	)		65,822			(1,233,474	)
Preferred stock dividends		—			—			—			16,321

(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(8,485	)	$	(404,337	)	$	65,822		$	(1,249,795	)

(Loss) earnings per share
Basic	$	(0.25	)	$	(0.56	)	$	2.07		$	(1.76	)

Diluted	$	(0.25	)	$	(0.56	)	$	2.06		$	(1.76	)

Weighted average number of common shares outstanding
Basic		34,290			718,373			31,750			708,788

Diluted		34,290			718,373			31,984			708,788

SandRidge Energy, Inc. and Subsidiaries Condensed Consolidated Balance Sheets (Unaudited)

(In thousands)


	September 30,			December 31,
	2017			2016
ASSETS
Current assets
Cash and cash equivalents	$	133,201		$	121,231
Restricted cash - collateral		—			50,000
Restricted cash - other		2,312			2,840
Accounts receivable, net		69,187			74,097
Derivative contracts		6,608			—
Prepaid expenses		2,334			5,375
Other current assets		8,045			3,633

Total current assets		221,687			257,176

Oil and natural gas properties, using full cost method of accounting
Proved		1,004,370			840,201
Unproved		103,533			74,937
Less: accumulated depreciation, depletion and impairment		(432,564	)		(353,030	)

		675,339			562,108

Other property, plant and equipment, net		238,420			255,824
Derivative contracts		2,010			—
Other assets		1,327			6,284

Total assets	$	1,138,783		$	1,081,392

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses	$	127,941		$	116,517
Derivative contracts		8			27,538
Asset retirement obligations		62,144			66,154
Other current liabilities		7,422			3,497

Total current liabilities		197,515			213,706

Long-term debt		37,601			305,308
Derivative contracts		—			2,176
Asset retirement obligations		42,698			40,327
Other long-term obligations		2,686			6,958

Total liabilities		280,500			568,475

Commitments and contingencies
Stockholders’ Equity
Common stock, $0.001 par value; 250,000 shares authorized; 35,801 issued and outstanding at September 30, 2017 and 21,042 issued and 19,635 outstanding at December 31, 2016		36			20
Warrants		88,475			88,381
Additional paid-in capital		1,037,932			758,498
Accumulated deficit		(268,160	)		(333,982	)

Total stockholders’ equity		858,283			512,917

Total liabilities and stockholders’ equity	$	1,138,783		$	1,081,392

SandRidge Energy, Inc. and Subsidiaries Condensed Consolidated Cash Flows (Unaudited)

(In thousands)


	Nine Months Ended September 30,
	Successor			Predecessor
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	65,822		$	(1,233,474	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Provision for doubtful accounts		133			16,704
Depreciation, depletion and amortization		98,215			112,301
Impairment		3,475			718,194
Reorganization items, net		—			231,836
Debt issuance costs amortization		313			4,996
Amortization of premiums and discounts on debt		(231	)		2,734
Gain on extinguishment of debt		—			(41,179	)
Gain on debt derivatives		—			(1,324	)
Cash paid for early conversion of convertible notes		—			(33,452	)
(Gain) loss on derivative contracts		(46,024	)		4,823
Cash received on settlement of derivative contracts		7,700			72,608
Loss on settlement of contract		—			90,184
Cash paid on settlement of contract		—			(11,000	)
Stock-based compensation		12,616			9,075
Other		188			(3,260	)
Changes in operating assets and liabilities		5,699			(3,805	)

Net cash provided by (used in) operating activities		147,906			(64,039	)

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment		(152,743	)		(186,452	)
Acquisition of assets		(48,236	)		(1,328	)
Proceeds from sale of assets		19,769			20,090

Net cash used in investing activities		(181,210	)		(167,690	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		—			489,198
Repayments of borrowings		—			(40,000	)
Debt issuance costs		(1,488	)		(333	)
Cash paid for tax withholdings on vested stock awards		(3,766	)		(44	)

Net cash (used in) provided by financing activities		(5,254	)		448,821

NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH		(38,558	)		217,092
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year		174,071			435,588

CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of period	$	135,513		$	652,680

Supplemental Disclosure of Cash Flow Information
Cash paid for reorganization items	$	—		$	(11,836	)
Supplemental Disclosure of Noncash Investing and Financing Activities
Cumulative effect of adoption of ASU 2015-02	$	—		$	(247,566	)
Property, plant and equipment transferred in settlement of contract	$	—		$	(215,635	)
Change in accrued capital expenditures	$	(15,241	)	$	25,045
Equity issued for debt	$	(268,779	)	$	(4,409	)

Non-GAAP Financial Measures

Adjusted net income, operating cash flow, adjusted EBITDA, adjusted G&A per Boe, and net debt are non-GAAP financial measures.

The Company defines adjusted net income as net income before asset impairment, loss (gain) on derivative contracts, cash received upon settlement of derivative contracts, restructuring costs, drilling participation agreement transaction costs, oil field services – exit costs, reorganization items, net, employee incentive and retention and other expenses. The Company defines 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) income before income tax (benefit) expense, interest expense, depreciation and amortization – other and depreciation and depletion – oil and natural gas. Adjusted EBITDA, as presented herein, is EBITDA excluding asset impairment, stock-based compensation, loss (gain) on derivative contracts, cash received upon settlement of derivative contracts, loss on settlement of contract, restructuring costs, oil field services – exit costs, gain on extinguishment of debt, reorganization items employee incentive and retention and other various items. The Company defines adjusted G&A per Boe as general and administrative expense per Boe adjusted for certain non-recurring items, expressed on a per-Boe basis, and less stock-based compensation expense, expressed on a per-Boe basis.

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

Management also uses the supplemental financial measure of adjusted net income (loss), which excludes asset impairment, (gain) loss on derivative contracts, cash received on settlement of derivative contracts, restructuring costs, drilling participation agreement transaction costs, oil field services – exit costs, reorganization items, employee incentive and retention and other non-cash items from income available (loss applicable) to common stockholders. Management uses this financial measure as an indicator of the Company’s operational trends and performance relative to other oil and natural gas companies and believes it is more comparable to earnings estimates provided by securities analysts. Adjusted net income (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 reports and provides guidance on adjusted G&A per Boe because it believes this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes adjusted G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry. This non-GAAP measure allows for the analysis of general and administrative spend without regard to stock-based compensation programs, and other non-recurring cash items which can vary significantly between companies. Adjusted G&A per Boe is not a measure of financial performance under GAAP and should not be considered a substitute for general and administrative expense per Boe. Therefore, the Company’s Adjusted G&A per Boe may not be comparable to other companies’ similarly titled measures.

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.

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

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

(In thousands)


	Three Months Ended September 30,					Nine Months Ended September 30,
	Successor		Predecessor			Successor			Predecessor
	2017		2016			2017			2016
Net cash provided by (used in) operating activities	$	43,974	$	75,002		$	147,906		$	(64,039	)
Changes in operating assets and liabilities		2,107		(43,215	)		(5,699	)		3,805

Operating cash flow	$	46,081	$	31,787		$	142,207		$	(60,234	)

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

(In thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	Successor			Predecessor			Successor			Predecessor
	2017			2016			2017			2016
Net (loss) income	$	(8,485	)	$	(404,337	)	$	65,822		$	(1,233,474	)

Adjusted for
Income tax (benefit) expense		(8,457	)		4			(8,496	)		11
Interest expense		1,177			3,589			3,509			127,517
Depreciation and amortization - other		3,399			7,514			10,729			21,323
Depreciation and depletion - oil and natural gas		31,029			27,725			87,486			90,978

EBITDA		18,663			(365, 505	)		159,050			(993,645	)

Asset impairment		498			354,451			3,475			718,194
Stock-based compensation		2,961			1,247			10,789			4,291
Loss (gain) on derivative contracts		11,702			(338	)		(46,024	)		4,823
Cash received upon settlement of derivative contracts ⁽¹⁾		4,994			20,393			7,700			66,851
Loss on settlement of contract		—			—			—			90,184
Restructuring costs⁽²⁾		515			476			8,554			36,406
Drilling participation agreement transaction costs		2,881			—			2,881			—
Oil field services - exit costs		—			12			—			2,428
Gain on extinguishment of debt		—			—			—			(41,179	)
Reorganization items, net		—			42,754			—			243,672
Employee incentive and retention		—			9,724			—			20,141
Other		(477	)		1,521			(2,712	)		14,820

Adjusted EBITDA	$	41,737		$	64,735		$	143,713		$	166,986

⁽¹⁾	Excludes amounts received for early settlement of contracts in the nine-month period ended September 30, 2016.

⁽²⁾	Includes severance.

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

(In thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	Successor			Predecessor			Successor			Predecessor
	2017			2016			2017			2016
Net cash provided by (used in) operating activities	$	43,974		$	75,002		$	147,906		$	(64,039	)

Changes in operating assets and liabilities		2,107			(43,215	)		(5,699	)		3,805
Interest expense		1,177			3,589			3,509			127,517
Cash received on early settlement of derivative contracts		—			—			—			(17,894	)
Contractual maturity reached on previous early settlements		—			5,756			—			12,137
Cash paid on early conversion of convertible notes		—			—			—			33,452
Cash paid on settlement of contract		—			—			—			11,000
Restructuring costs⁽¹⁾⁽²⁾		515			498			6,729			31,328
Drilling participation agreement transaction costs		2,881			—			2,881			—
Income tax (benefit) expense		(8,457	)		4			(8,496	)		11
Oil field services - exit costs ⁽²⁾		—			13			—			2,386
Cash paid for reorganization items		—			11,836			—			11,836
Employee incentive and retention		—			9,724			—			20,141
Other		(460	)		1,528			(3,117	)		(4,694	)

Adjusted EBITDA	$	41,737		$	64,735		$	143,713		$	166,986

⁽¹⁾	Includes severance.

⁽²⁾	Excludes associated stock-based compensation.

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

Net Income Available (Loss Applicable) to Common Stockholders

(In thousands)


	Three Months Ended September 30,
	Successor						Predecessor
	2017						2016
	$			$/Diluted Share			$			$/Diluted Share
Net loss applicable to common stockholders	$	(8,485	)	$	(0.25	)	$	(404,337	)	$	(0.56	)

Asset impairment		498			0.01			354,451			0.49
Loss (gain) on derivative contracts		11,702			0.34			(338	)		0.00
Cash received upon settlement of derivative contracts ⁽¹⁾		4,994			0.15			20,393			0.03
Restructuring costs⁽²⁾		515			0.02			476			0.00
Drilling participation agreement transaction costs		2,881			0.09			—			—
Oil field services - exit costs		—			—			12			0.00
Reorganization items, net		—			—			42,754			0.06
Employee incentive and retention		—			—			9,724			0.02
Other		(215	)		(0.01	)		2,200			0.00

Adjusted net income available to common stockholders	$	11,890		$	0.35		$	25,335		$	0.04


	Basic			Diluted⁽³⁾			Basic			Diluted⁽³⁾
Weighted average number of common shares outstanding		34,290			34,388			718,373			718,373

Total adjusted net income per share	$	0.35		$	0.35		$	0.04		$	0.04


	Nine Months Ended September 30,
	Successor						Predecessor
	2017						2016
	$			$/Diluted Share			$			$/Diluted Share
Net income available (loss applicable) to common stockholders	$	65,822		$	2.06		$	(1,249,795	)	$	(1.76	)

Asset impairment		3,475			0.11			718,194			1.01
(Gain) loss on derivative contracts		(46,024	)		(1.44	)		4,823			0.01
Cash received upon settlement of derivative contracts ⁽¹⁾		7,700			0.24			66,851			0.09
Loss on settlement of contract		—			—			90,184			0.13
Restructuring costs⁽²⁾		8,554			0.27			36,406			0.05
Drilling participation agreement transaction costs		2,881			0.09			—			—
Oil field services - exit costs		—			—			2,428			0.00
Gain on extinguishment of debt		—			—			(41,179	)		(0.06	)
Reorganization items, net		—			—			243,672			0.34
Employee incentive and retention		—			—			20,141			0.03
Other		(1,642	)		(0.06	)		15,410			0.03

Adjusted net income available (loss applicable) to common stockholders	$	40,766		$	1.27		$	(92,865	)	$	(0.13	)


	Basic			Diluted⁽³⁾			Basic			Diluted⁽³⁾
Weighted average number of common shares outstanding		31,750			31,984			708,788			708,788

Total adjusted net income (loss) per share	$	1.28		$	1.27		$	(0.13	)	$	(0.13	)

⁽¹⁾	Excludes amounts received for early settlement of contracts in the 2016 periods.

⁽²⁾	Includes severance.

⁽³⁾	Weighted average fully diluted common shares outstanding for certain periods presented includes shares that are considered antidilutive for calculating loss per share in accordance with GAAP.

For further information, please contact:

Justin M. Lewellen

Director of 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 the Company’s corporate strategies, future operations, and development plans and appraisal programs, projected acreage position, drilling inventory and locations, estimated oil, and natural gas and natural gas liquids production, rates of return, reserves, price realizations and differentials, hedging program, projected operating, general and administrative and other costs, projected capital expenditures, tax rates, efficiency and cost reduction initiative outcomes, liquidity and capital structure and infrastructure assessment and investment. 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, 2016 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.