OKLAHOMA CITY, Feb. 22, 2017 /PRNewswire/ -- 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 23rd 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
|
|
|
|
|
1)
|
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 policy election to present transportation costs as a
reduction from revenue
|
|
(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
|
|
Period
from
|
|
Period
from
|
|
Three
Months
|
|
|
|
|
|
|
|
Year
Ended
|
|
October 2, 2016
through
|
|
January 1, 2016
through
|
|
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
|
|
Period
from
|
|
Period
from
|
|
Three
Months
|
|
|
|
|
|
|
|
Year
Ended
|
|
October 2, 2016
through
|
|
January 1, 2016
through
|
|
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,
|
|
December
31,
|
|
2016
|
|
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
|
|
Period
from
|
|
Period
from
|
|
Three
Months
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
October 2, 2016
through
|
|
January 1, 2016
through
|
|
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
|
|
Period
from
|
|
Period
from
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
October 2, 2016
through
|
|
January 1, 2016
through
|
|
Year
Ended
|
|
|
|
|
|
|
December 31,
2016
|
|
December 31,
2016
|
|
October 1,
2016
|
|
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
|
|
Period
from
|
|
Period
from
|
|
Three
Months
|
|
|
|
|
|
|
|
Year
Ended
|
|
October 2, 2016
through
|
|
January 1, 2016
through
|
|
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
|
|
Period
from
|
|
Period
from
|
|
Three
Months
|
|
|
|
|
|
|
|
Year
Ended
|
|
October 2, 2016
through
|
|
January 1, 2016
through
|
|
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
|
|
Period
from
|
|
Period
from
|
|
Three
Months
|
|
|
|
|
|
|
|
Year
Ended
|
|
October 2, 2016
through
|
|
January 1, 2016
through
|
|
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
|
|
Period
from
|
|
Period
from
|
|
Three
Months
|
|
|
|
|
|
|
|
Year
Ended
|
|
October 2, 2016
through
|
|
January 1, 2016
through
|
|
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,
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
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.
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SOURCE SandRidge Energy, Inc.