OKLAHOMA CITY, Nov. 8, 2016 /PRNewswire/ -- SandRidge Energy,
Inc. (the "Company") (NYSE:SD) today announced financial and
operational results for the quarter ended September 30, 2016.
Production in the third quarter was 4.6 MMBoe (49.6 MBoepd, 28%
oil, 24% NGLs, 48% natural gas). One drilling rig was active in
Oklahoma during the entire
quarter, and one drilling rig was active for part of the quarter in
the North Park Basin of
Colorado, with well completion
activity continuing into the fourth quarter. Capital expenditures
were $52 million during the third
quarter, bringing the total amount invested to $161 million through the third quarter of 2016,
excluding acquisitions. Capital expenditure and operational
guidance, noted below, has been updated for 2016 in addition to
introducing 2017 capital expenditure guidance.
The Company reported a net loss of $404
million and net cash from operating activities of
$75 million for the third 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 $25
million and "adjusted operating cash flow" totaled
$32 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 $65 million.
The Company has defined and reconciled adjusted net income,
adjusted operating cash flow and adjusted EBITDA to the most
directly comparable U.S. generally accepted accounting principles
(GAAP) financial measures in supporting tables at the conclusion of
this press release under the "Non-GAAP Financial Measures"
beginning on page 15.
James Bennett, SandRidge
President and CEO said, "2016 has been a watershed year for
SandRidge. The Company successfully restructured its balance sheet
and currently has no cash interest burden and over $500 million of liquidity. We intend to conserve
capital by reducing our 2016 capital expenditures from our original
plan of $285 million to $220-240 million. Our multi and extended lateral
program is more capital efficient every quarter. In the
Mid-Continent, recent drilling and completion costs are below
$2 million per lateral, with the
completion of a dual two-mile extended lateral, the equivalent of
four one-mile laterals in a single well, for $1.7 million per lateral. Recent drilling
activity included our first Niobrara two-mile extended lateral,
which demonstrates an attractive and repeatable combination of well
costs and oil productivity. With an inventory of 1,300 proved and
probable Niobrara laterals, we will resume Niobrara drilling in
early 2017, further targeting additional productive Niobrara oil
benches, tighter well spacing, and higher oil recoveries per well.
We will continue using extended laterals in both of our plays."
Highlights during and subsequent to the third quarter
include:
Relisted October 4th on NYSE with Ticker Symbol
"SD"
Continuing to Improve
Capital Efficiency by Expanding Use of Multi and Extended
Laterals1
First Niobrara Extended
Lateral and First Niobrara Test of an Additional Bench Drilled in
Third Quarter, Completed and Flowing Back in Fourth
Quarter
North Park Niobrara Type
Curve of 315 MBoe (86% Oil) EUR per Single Lateral
Drilled Six Mid-Continent
Laterals and Three North Park Basin Laterals in Third
Quarter
John
Suter, SVP of Operations, Named Successor to Steve Turk who is Retiring as COO
Third Quarter Production of
4.6 MMBoe (49.6 MBoepd, 28% Oil, 24% NGLs, 48% Natural
Gas)
Hedge Positions Added for
Remainder of 2016 and in 2017 and 2018
Updating 2016 Guidance and
Introducing 2017 Capital Expenditure Guidance
Total Liquidity of
$536 Million Including Unrestricted
Cash of $111 Million and $425 Million Available Under Senior Credit
Facility as of October
31st
(1) A "lateral" is
defined as a single one-mile section lateral whereas an "extended
lateral" is defined as a two-mile lateral drilled across two
sections, and a "multilateral" defined as two or more one-mile
laterals drilled within a one-mile section.
|
Bennett went on to say, "SandRidge expects to create
value with competitive project IRRs from both the high-graded
harvest of our Mid-Continent position and the portfolio
diversification and potential long term oil growth of our
emerging North Park Niobrara project and non-Mississippian targets
in the Mid-Continent. Our larger goals are to increase oil
weighting, reduce cost structure, and effectively manage a
portfolio of competitive projects already in hand, while looking
for additional opportunities to create resource value. We plan to
achieve all of this while protecting our balance sheet, liquidity
and minimizing cash flow outspend."
COO Steve Turk Retiring, SandRidge Names John Suter to Become
New COO
Effective December
31st, SandRidge Chief Operating Officer (COO)
Steve Turk, 65, will retire, after
having served in this leadership role since March 2015.
John Suter, 56, now Senior Vice
President of Operations, is being promoted to COO effective
December 1st.
James Bennett, SandRidge CEO
and President said, "I want to thank Steve for his
contributions to SandRidge during his tenure with the company. His
extensive experience and informed decision making approach have
provided consistent, steady leadership. Through our succession
planning program, John's promotion to COO is something we have
prepared for. John has taken on additional responsibilities across
all of our operating areas in recent months and we expect the
transition to be seamless."
Mr. Suter joined SandRidge in April
2015 as Senior Vice President of Mid-Continent Operations,
bringing with him extensive experience in the exploration and
production sector, including most recently serving as
Vice President of the Woodford
business unit at American Energy Partners, LP from November 2013. From May
2010 to September 2013, he
served as Vice President of Operations for Chesapeake Energy
Corporation's Western Division, and before that, as
Chesapeake's District Manager for the Barnett Shale and
Southern Oklahoma assets. Before
joining Chesapeake Energy, Mr. Suter served in various
operational roles at Continental Resources, Inc., Cabot Oil &
Gas Corporation and Petro-Lewis Corporation. He holds a Bachelor of
Science degree in Petroleum Engineering from Texas Tech University.
Mid-Continent Assets in Oklahoma and Kansas
- Third quarter production of 4.3 MMBoe (46.2 MBoepd, 24% oil,
25% NGLs, 51% natural gas)
- Drilled six laterals in the third quarter, bringing three
laterals online
- 24 laterals drilled in the first nine months of 2016 with all
Mid-Continent activity focused in Oklahoma
- First nine months of Mississippian drilling and completion
costs averaged $1.9 million per
lateral or $392 per completed foot, a
~26% reduction from all of 2015
Multi and Extended Lateral Development
- 100% multi and extended lateral Mississippian drilling in
2016
- First North Park Niobrara extended lateral drilled
- 100% multi and extended lateral development planned in 2017
across both Niobrara and Mid-Continent assets
In 2013, SandRidge pioneered Mississippian multilateral
technology, the technique of drilling two to four laterals from a
single vertical wellbore. In late 2014, the Company's expanded
development included extended laterals.
Since inception of the multi and extended lateral program, the
Company has drilled and completed 123 laterals using multilateral
design and 50 laterals using extended lateral design. Most notably,
SandRidge has uniquely applied the full section development
multilateral design, where three or more laterals are drilled from
a single wellbore. Both multi and extended laterals enable the
Company to reduce drilling and completion costs and decrease
operating expenses with common well site facilities and artificial
lift equipment.
In the first nine months of 2016, SandRidge drilled and
completed 17 laterals using multi and extended lateral designs in
the Mid-Continent, including 100% Mississippian multi and extended
lateral drilling. The previously reported Dettle 2408 1-29 20H, the
first Mississippian dual extended lateral (two two-mile laterals),
produced a 30-Day IP of 1,099 Boepd2 (60% oil) and was
drilled and completed for $6.8
million ($1.7 million per
lateral).
Another example, the Earl 2414 1-11H 14H, a Chester extended
lateral development well, was drilled for $4.3 million ($2.1
million per lateral), and produced a 30-Day IP of 560 Boepd
(62% oil), matching expectations.
In the third quarter, the Richey 2407 1-21H, a Mississippian
full section development well exceeded expectations with a
30-Day IP of 688 Boepd (66% oil) and was drilled and completed for
a total of $5.3 million ($1.8 million per lateral).
Most recently, technical teams applied extended lateral drilling
technology in the Company's North
Park Basin asset by drilling and completing an extended
lateral Niobrara well, the Castle 1-17H 20. Although early,
initial rates are outperforming expectations. The Company plans to
drill 100% multi and extended laterals in 2017 across both the
North Park Basin and Mid-Continent
assets.
(2) Calculated as the
highest consecutive 30-Day average production rate during the early
life of a well.
|
Niobrara Asset in North Park
Basin, Jackson County,
Colorado
- Third quarter production of 161 MBo (1.8 MBopd), an increase of
49% compared to the second quarter of 2016
- Averaged 3.3 MBopd the second half of October, including
production from 11 Niobrara laterals drilled in 2016
- North Park Niobrara type curve of 315 MBoe (86% oil) per single
lateral, supported by cumulative production from 14 laterals
- Drilled three laterals, completed four laterals, and
brought three laterals online during the third quarter
- Drilled first two-mile extended lateral, the Castle 1-17H 20,
for below $7 million, less than
$3.5 million per lateral
SandRidge drilled 10 wells with 11 total laterals in the
North Park Basin in 2016. The goal
for the first five wells was to test initial drilling and
completion techniques in the new basin and to prove production
performance. The first five wells demonstrated
consistent performance to establish the play. The Company's
first Niobrara well, the Gregory 1-9H, exceeded type curve
production expectations with a previously reported 30-Day IP of 550
Boepd (89% oil). The well has been online for over seven
months, averaged 310 Boepd (84% oil) during the month of
October, and has produced a total of ~75 MBo. In the second
quarter, four additional laterals were drilled, completed, and
brought online, with an average 30-Day IP of 460 Boepd. Averaging
91% oil, all four wells met or exceeded type curve performance
estimates and indicated consistent performance in this area of
development.
The goal for the second five well package was to test concepts
related to various targeting, drilling and completion techniques.
In the second quarter, a grouping of three laterals utilizing batch
drilling and zipper frac completions improved cycle times. This
lateral grouping, now under evaluation, used a combination of
crosslinked gel and slickwater frac systems. In the third quarter,
three additional laterals were drilled. The first Niobrara extended
lateral, the Castle 1-17H 20, and a lateral testing a shallower
Niobrara bench, the Hebron 4-18H,
were completed and brought online in the fourth quarter. Results
for this five well pilot program are expected to be reported in the
fourth quarter earnings release.
Drilling and completion cost reductions have been an ongoing
focus throughout the year. Drilling efficiencies, such as mud and
bit system advances, reduced overall drilling cycle times by 69%
since the beginning of the program. Current spud to rig release
cycle time is averaging 11 days. Additionally, further cost
reductions from extended lateral drilling are expected to deliver
wells costs of less than $7 million
($3.5 million per lateral) in 2017,
supported by the highlighted recent extended lateral Castle 1-17H
20.
Construction of the Big Horn Central Tank Battery (CTB), which
became operational in mid-October, has further advanced our field
development. This facility will be the prototype for future full
field development and supports all 11 laterals drilled in 2016.
Future facility expansion will support production for up to 70
laterals at the Big Horn CTB, and the shared gathering concept will
reduce the overall drilling footprint, wellsite facility costs and
operating costs. Additionally, the Company completed a summer
construction program building roads, pads and flow lines in advance
of continued 2017 development. Aiding future well placement, a 64
square mile 3D seismic survey, planned for early 2017 will be
merged with and is complementary to the existing 54 square mile 3D
survey.
Other Operational Updates
- During the third quarter, Permian Central Basin Platform
properties produced 153 MBoe (1.7 MBoepd, 80% oil, 13% NGLs, 7%
natural gas)
Key Financial Results
Third Quarter
- Adjusted EBITDA, net of Noncontrolling Interest, was $65
million for third quarter 2016 compared to $118
million in third quarter 2015
- Adjusted operating cash flow of $32 million for third
quarter 2016 compared to $45 million in third quarter
2015
- Adjusted net income of $25 million for third quarter 2016
compared to adjusted net loss of $45 million in third quarter
2015
Nine Months
- Adjusted EBITDA, net of Noncontrolling Interest, was $169
million in the first nine months of 2016 compared to $510
million in first nine months of 2015, pro forma for
divestitures
- Adjusted operating cash flow of ($60) million in the
first nine months of 2016 compared to $302 million in the
first nine months of
2015
- Adjusted net loss of $93 million in the first nine months
of 2016 compared to adjusted net loss of $61 million in the
first nine months of 2015
Hedging Update
During and after the third quarter, SandRidge added oil and
natural gas hedge positions through the remainder of 2016, while
also adding positions in both 2017 and 2018. For the calendar year
of 2017, the Company now has approximately 2.6 million barrels of
oil hedged at an average WTI price of $51.45 as well as 29.2 billion cubic feet of
natural gas hedged at an average price of $3.19 per MMBtu. For 2018, the Company has
approximately 1.1 million barrels of oil hedged at an average WTI
price of $55.10.
Guidance Update
Capital expenditures in 2016 are now anticipated to be
$220 to $240 million for the full
year (midpoint reduced $10 million vs
prior guidance), with production estimates ranging from 19.0 to
19.4 MMBoe (100 MBoe greater than prior guidance midpoint). The
production estimate includes a 200 MBoe contingency for potential
weather downtime as was experienced in late 2015.
The Company is in the process of developing its capital
expenditures budget for 2017 and, in the current pricing
environment, expects that total capital expenditures will be less
than $200 million in 2017.
Restructuring Details and Liquidity
- 20.6 million common shares outstanding
- 14.8 million shares issuable upon conversion of mandatory
convertible notes
- 4.9 million warrants exercisable at $41.34 (net share settlement); 2.1 million
warrants exercisable at $42.03 (net
share settlement)
- No cash interest expense under current capital structure
including undrawn revolver, $35
million secured building note and $278 million of zero interest bearing,
mandatorily convertible notes
- $3.7 million par value of
convertible notes converted as of October
31st
- No leverage or interest coverage financial covenants, only
asset coverage ratio until October
2018
- No borrowing base redeterminations for approximately two
years
- $536 million of liquidity as of
October 31st, including
$111 million of unrestricted cash and
a $425 million undrawn revolver
New Board Appointments
Effective October 4, 2016, the
composition of SandRidge Energy's five person Board of Directors
consisted of:
John V. Genova
(Chairman) earned his Bachelor of Science degree in
Chemical and Petroleum Refining Engineering from the Colorado School of Mines in 1976. He joined Exxon
in the Company's Baton Rouge Refinery in 1976. At Exxon, he
held a number of positions of increasing responsibility in the
Refining, Supply and Natural Gas functions. Immediately
following the public announcement of the Exxon and Mobil merger,
Mr. Genova led the development of a $20
billion integrated natural gas project proposal for
Saudi Arabia and served as the
lead Exxon/Mobil merger natural gas negotiator with the European
Commission. Following approval of the Exxon and Mobil merger,
he was named Director, International Gas Marketing, ExxonMobil
International Limited. Subsequently, he was appointed
Executive Assistant to the Chairman, Lee
Raymond, and the General Manager of Corporate Planning of
Exxon Mobil Corporation on April 1,
2002. In this position, he served as an Officer of
ExxonMobil. In April 2004, Mr.
Genova became a Director of the Board of Encore Acquisition Company
and served on the Audit Committee until the company's merger with
Denbury Resources in early 2010. In May 2008, Mr. Genova was appointed as President
and CEO of Sterling Chemicals where he led the creation of
significant value before successfully completing the sale of the
company to Eastman Chemical.
James D. Bennett
has served as President and Chief Executive Officer of the Company
since June 2013. Prior to commencing
service in his current positions, he served as President and Chief
Financial Officer from March 2013
until June 2013 and Executive Vice
President and Chief Financial Officer from January 2011 until March
2013. Prior to joining the Company, Mr. Bennett was Managing
Director for White Deer Energy, a private equity fund focused on
the exploration and production, oilfield service and equipment, and
midstream sectors of the oil and gas industry. From 2006 to 2009,
Mr. Bennett was employed by GSO Capital Partners L.P., where he
served in various capacities, including as its Managing Director.
Mr. Bennett graduated with a B.B.A. with a major in finance from
Texas Tech University. Mr. Bennett has
served on the boards of directors of the general partner of
Cheniere Energy Partners L.P. and PostRock Energy Corporation.
Michael (Mike) L.
Bennett, no relation to James Bennett, has over thirty-six years of
experience in the chemical industry and serves as a member of the
board of directors and the audit committee of Alliant Energy,
Chairman of the board of directors of OCI N.V., and Chairman of the
board of directors of OCI Partners LP. Mr. Bennett served as
President and CEO of Terra Industries, Inc. from 2001 until its
sale to CF Industries in 2010. He is a past Chairman of The
Fertilizer Institute and the Methanol Institute.
William (Bill) M. Griffin,
Jr. is an independent energy advisor with over
thirty-five years of technical and leadership experience with
active public and privately owned upstream energy organizations.
Mr. Griffin most recently served as President and Chief Executive
Officer of privately held Petro Harvester Oil & Gas. Mr.
Griffin's background also includes senior leadership positions as
President of Ironwood Oil & Gas, Senior Vice President of El
Paso Exploration and Production Company and Vice President of Sonat
Exploration Company. In addition to the board of Petro
Harvester, Mr. Griffin has also served as a director for Black
Warrior Methane Corporation and Four Star Oil & Gas Company.
Mr. Griffin began his career with Texas Oil & Gas Corporation
and is a registered professional engineer with a B.S. in mechanical
engineering from Texas A&M
University.
David J. Kornder
has over twenty-five years of experience and has previously served
as Chief Executive Officer of Cornerstone Natural Resources, LLC,
Chief Financial Officer of Petrie
Parkman & Co., an energy investment bank, and as
Executive Vice President and Chief Financial Officer of Patina Oil
& Gas Corporation from 1996 through its acquisition by Noble
Energy, Inc. in May 2005. Prior to
that, Mr. Kornder began his career at Deloitte & Touche
LLP.
Conference Call Details
The Company will host a conference call to discuss these results
on Wednesday, November 9, 2016 at
8:00 am CT. 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 86082124. An audio replay of the call will be available
from November 9, 2016 until
11:59 pm CT on December 9, 2016. The number to access the
conference call replay from within the U.S. is (855) 859-2056 and
from outside the U.S. is (404) 537-3406. The passcode for the
replay is 86082124.
Operational and Financial Statistics
Information regarding the Company's production, pricing, costs
and earnings is presented below:
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Production -
Total
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
1,282
|
|
2,262
|
|
4,315
|
|
7,604
|
NGL (MBbl)
|
|
1,103
|
|
1,246
|
|
3,358
|
|
3,883
|
Natural gas
(MMcf)
|
|
13,079
|
|
23,058
|
|
44,124
|
|
71,133
|
Oil equivalent
(MBoe)
|
|
4,565
|
|
7,351
|
|
15,027
|
|
23,343
|
Daily production
(MBoed)
|
|
49.6
|
|
79.9
|
|
54.8
|
|
85.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Production -
Mid-Continent
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
998
|
|
1,938
|
|
3,597
|
|
6,554
|
NGL (MBbl)
|
|
1,084
|
|
1,202
|
|
3,301
|
|
3,764
|
Natural gas
(MMcf)
|
|
13,016
|
|
20,128
|
|
43,330
|
|
62,292
|
Oil equivalent
(MBoe)
|
|
4,250
|
|
6,495
|
|
14,119
|
|
20,700
|
Daily production
(MBoed)
|
|
46.2
|
|
70.6
|
|
51.5
|
|
75.8
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price per
unit
|
|
|
|
|
|
|
|
|
Realized oil price
per barrel - as reported
|
|
$
42.82
|
|
$
43.33
|
|
$
36.85
|
|
$
47.55
|
Realized impact of
derivatives per barrel
|
|
10.93
|
|
28.85
|
|
14.20
|
|
32.87
|
Net realized price
per barrel
|
|
$
53.75
|
|
$
72.18
|
|
$
51.05
|
|
$
80.42
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized NGL price
per barrel - as reported
|
|
$
13.90
|
|
$
13.29
|
|
$
12.67
|
|
$
14.69
|
Realized impact of
derivatives per barrel
|
|
-
|
|
-
|
|
-
|
|
-
|
Net realized price
per barrel
|
|
$
13.90
|
|
$
13.29
|
|
$
12.67
|
|
$
14.69
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized natural gas
price per Mcf - as reported
|
|
$
2.27
|
|
$
2.19
|
|
$
1.78
|
|
$
2.20
|
Realized impact of
derivatives per Mcf
|
|
0.05
|
|
0.09
|
|
(0.01)
|
|
0.41
|
Net realized price
per Mcf
|
|
$
2.32
|
|
$
2.28
|
|
$
1.77
|
|
$
2.61
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price per
Boe - as reported
|
|
$
21.89
|
|
$
22.46
|
|
$
18.63
|
|
$
24.65
|
Net realized price
per Boe - including impact of derivatives
|
|
$
25.10
|
|
$
31.61
|
|
$
22.70
|
|
$
36.58
|
|
|
|
|
|
|
|
|
|
|
|
|
Average cost per
Boe
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
$
8.68
|
|
$
9.91
|
|
$
8.63
|
|
$
10.46
|
Production
taxes
|
|
0.50
|
|
0.50
|
|
0.41
|
|
0.54
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
administrative
|
|
|
|
|
|
|
|
|
|
General and
administrative, excluding stock-based compensation
|
|
$
3.99
|
|
$
4.17
|
|
$
7.00
|
|
$
4.01
|
|
Stock-based
compensation
|
|
2.40
|
|
0.49
|
|
1.94
|
|
0.65
|
|
Total general and
administrative
|
|
$
6.38
|
|
$
4.66
|
|
$
8.95
|
|
$
4.66
|
|
|
|
|
|
|
|
|
|
|
|
|
General and
administrative - adjusted
|
|
|
|
|
|
|
|
|
|
General and
administrative, excluding stock-based compensation
(1)
|
|
$
3.88
|
|
$
3.29
|
|
$
3.69
|
|
$
3.37
|
|
Stock-based
compensation (2)
|
|
0.98
|
|
0.48
|
|
0.71
|
|
0.44
|
|
Total general and
administrative - adjusted
|
|
$
4.86
|
|
$
3.77
|
|
$
4.40
|
|
$
3.81
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion
(3)
|
|
$
6.07
|
|
$
9.20
|
|
$
6.05
|
|
$
11.58
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
cost per Boe
|
|
|
|
|
|
|
|
|
Mid-Continent
|
|
$
7.76
|
|
$
7.09
|
|
$
7.58
|
|
$
7.75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Excludes severance,
doubtful receivable write-off and restructuring costs totaling $0.5
million and $49.8 million for the three and nine-month periods
ended September 30, 2016, respectively. Excludes severance, legal
settlements and shareholder litigation totaling $6.4 million and
$14.9 million for the three and nine-month periods ended September
30, 2015, respectively.
|
(2)
|
Three and nine-month
periods ended September 30, 2016 exclude $6.5 million and $18.5
million,respectively, for employee incentive and retention and the
acceleration of certain stock awards. Three and nine-month periods
ended September 30, 2015 exclude $0.1 million and $4.8 million,
respectively, for the acceleration of certain stock
awards.
|
(3)
|
Includes accretion of
asset retirement obligation.
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
The table below summarizes the Company's capital expenditures
for the three and nine-month periods ended September 30, 2016 and 2015:
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and
production
|
|
|
|
|
|
|
|
|
|
Mid-Continent
|
|
$
16,273
|
|
$
87,183
|
|
$
79,845
|
|
$
511,789
|
|
Rockies
|
|
31,368
|
|
-
|
|
72,164
|
|
-
|
|
Other
|
|
(496)
|
|
675
|
|
65
|
|
4,257
|
|
|
|
|
|
47,145
|
|
87,858
|
|
152,074
|
|
516,046
|
Leasehold and
geophysical
|
|
|
|
|
|
|
|
|
|
Mid-Continent
|
|
3,166
|
|
15,848
|
|
(2,771)
|
|
42,434
|
|
Rockies
|
|
594
|
|
-
|
|
1,361
|
|
-
|
|
Other
|
|
116
|
|
651
|
|
3,174
|
|
4,391
|
|
|
|
|
|
3,876
|
|
16,499
|
|
1,764
|
|
46,825
|
|
|
|
|
|
|
|
|
|
|
|
|
Inventory
|
|
(443)
|
|
1,656
|
|
1,789
|
|
(3,356)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total exploration and
development
|
|
50,578
|
|
106,013
|
|
155,627
|
|
559,515
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and oil
field services
|
|
(248)
|
|
259
|
|
23
|
|
2,732
|
Midstream
|
|
1,166
|
|
3,719
|
|
3,085
|
|
20,400
|
Other -
general
|
|
279
|
|
3,306
|
|
2,672
|
|
18,405
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital
expenditures, excluding acquisitions
|
|
51,775
|
|
113,297
|
|
161,407
|
|
601,052
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions
|
|
(70)
|
|
(244)
|
|
1,327
|
|
3,231
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital
expenditures
|
|
$
51,705
|
|
$
113,053
|
|
$
162,734
|
|
$
604,283
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts
Subsequent to September 30, 2016,
the Company entered into additional oil and gas swap contracts for
the remainder of 2016, as well as 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 2016 as of November 8, 2016:
|
|
|
|
4Q
2016
|
|
|
|
|
|
|
|
|
Oil
(MMBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
Volume
|
|
1.29
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
$56.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(Bcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
Volume
|
|
10.92
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
$2.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis
(Bcf)
|
|
|
|
|
|
|
|
|
|
|
|
Swap
Volume
|
|
0.92
|
|
|
|
|
|
|
|
|
|
Swap
|
|
|
$(0.38)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter
Ending
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3/31/2017
|
|
6/30/2017
|
|
9/30/2017
|
|
12/31/2017
|
|
FY
2017
|
Oil
(MMBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
Volume
|
|
0.63
|
|
0.64
|
|
0.64
|
|
0.64
|
|
2.56
|
|
Swap
|
|
|
$51.45
|
|
$51.45
|
|
$51.45
|
|
$51.45
|
|
$51.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(Bcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
Volume
|
|
7.20
|
|
7.28
|
|
7.36
|
|
7.36
|
|
29.20
|
|
Swap
|
|
|
$3.19
|
|
$3.19
|
|
$3.19
|
|
$3.19
|
|
$3.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3/31/2018
|
|
6/30/2018
|
|
9/30/2018
|
|
12/31/2018
|
|
FY
2018
|
Oil
(MMBbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap
Volume
|
|
0.27
|
|
0.27
|
|
0.28
|
|
0.28
|
|
1.10
|
|
Swap
|
|
|
$55.10
|
|
$55.10
|
|
$55.10
|
|
$55.10
|
|
$55.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet
The Company's capital structure, pro forma for its restructuring
and as of October 31, 2016 is
presented below.
Proforma Capital
Structure
|
$ in
Millions
|
Debt at Principal
Value
|
as of Jun 30,
2016
|
Restructuring
|
Pro Forma
as of Oct 31, 2016
|
|
|
|
|
|
|
|
|
Secured
Debt1
|
$
-
|
$
35
|
$
35
|
8.75% Second
Lien Secured Notes due 2020
|
1,328
|
(1,328)
|
-
|
|
|
|
|
Unsecured
Notes:
|
|
|
|
8.75% Senior Unsecured
Notes due 2020
|
$
396
|
$
(396)
|
$
-
|
7.50% Senior Unsecured
Notes due 2021
|
758
|
(758)
|
-
|
8.125% Senior Unsecured
Notes due 2022
|
528
|
(528)
|
-
|
7.50% Senior Unsecured
Notes due 2023
|
544
|
(544)
|
-
|
Sub-Total Unsecured
Notes
|
$
2,225
|
$
(2,225)
|
$
-
|
|
|
|
|
Unsecured Convertible
Notes:
|
|
|
|
8.125% Senior
Unsecured Convertible Notes due 2022
|
$
41
|
$
(41)
|
$
-
|
7.50% Senior
Unsecured Convertible Notes due 2023
|
47
|
(47)
|
-
|
Total Senior
Debt
|
$
3,641
|
$
(3,606)
|
$
35
|
|
|
|
|
0.00%
Convertible Senior Subordinated Notes Due
20202
|
$
-
|
$
278
|
$
278
|
Total
Debt
|
$
3,641
|
$
(3,328)
|
$
313
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquidity
|
|
|
|
RBL Borrowing
Base3
|
$
500
|
$
(75)
|
$
425
|
|
|
|
|
RBL
Available
|
-
|
425
|
425
|
Cash
|
634
|
(523)
|
111
|
Total
Liquidity
|
$
634
|
$
(98)
|
$
536
|
|
|
|
|
1) Secured by
mortgages on the Company's non-oil and gas real
property.
|
2) $3.7 million
par value of conversions as of October 31st.
|
3) Excludes
approximately $10 million of letters of credit.
|
2016 Operational Guidance Update
The Company is providing an update to its previously disclosed
2016 capital budgeting guidance from $225 to
$255 million, estimating that it will now spend $220 to $240 million for the full year with total
production ranging from 19.0 to 19.4 MMBoe. Capital expenditure,
production, and other operational guidance detail for the full year
of 2016 can be found below.
|
Total
Company
|
|
Total
Company
|
|
|
|
|
Projection as
of
|
|
Projection as
of
|
|
|
|
|
September 28,
2016
|
|
November 8,
2016
|
Production
|
|
|
|
|
Oil
(MMBbls)
|
5.3 - 5.5
|
|
5.4 -
5.5
|
|
Natural Gas Liquids
(MMBbls)
|
4.1 - 4.3
|
|
4.1 - 4.3
|
|
Total Liquids
(MMBbls)
|
9.4 - 9.8
|
|
9.5 -
9.8
|
|
Natural Gas
(Bcf)
|
56.7 -
56.8
|
|
57.0 -
57.3
|
|
Total
(MMBoe)
|
18.9 -
19.3
|
|
19.0 -
19.4
|
|
|
|
|
|
|
|
Price
Realization
|
|
|
|
|
Oil (differential
below NYMEX WTI)
|
$3.75
|
|
$3.75
|
|
Natural Gas Liquids
(realized % of NYMEX WTI)
|
27%
|
|
30%
|
|
Natural Gas
(differential below NYMEX Henry Hub)
|
$0.50
|
|
$0.50
|
|
|
|
|
|
|
|
Costs per
Boe
|
|
|
|
|
LOE
|
|
$9.00 -
$9.20
|
|
$8.80 -
$9.00
|
|
DD&A - oil &
gas1
|
5.10 -
5.50
|
|
5.80 -
6.20
|
|
DD&A -
other
|
1.40 -
1.45
|
|
1.40 -
1.45
|
|
Total
DD&A
|
$6.50 -
$6.95
|
|
$7.20 -
$7.65
|
|
Adjusted G&A -
Cash2
|
$4.25 -
$4.50
|
|
$3.70 -
$3.90
|
|
|
|
|
|
|
|
% of
Revenue
|
|
|
|
|
Production
Taxes
|
2.00% -
2.25%
|
|
2.00% -
2.25%
|
|
|
|
|
|
|
|
Corporate Tax
Rate
|
0%
|
|
0%
|
Deferral Tax
Rate
|
0%
|
|
0%
|
|
|
|
|
|
|
|
Capital
Expenditures ($ in millions)
|
Drilling and
Completing
|
Previous
|
|
New
|
|
Mid-Continent
|
$45 - $50
|
|
$42.5 -
$47.5
|
|
North Park
Basin
|
55 - 60
|
|
55 - 60
|
|
Other3
|
25 - 30
|
|
25
|
Total Drilling and
Completing
|
$125 -
$140
|
|
$122.5 -
$132.5
|
|
|
|
|
|
|
|
Other
E&P
|
|
|
|
|
Land, G&G, and
Seismic
|
$10 - $15
|
|
$10 - $15
|
|
Infrastructure4
|
25 - 30
|
|
20 -
22.5
|
|
Workover
|
35 - 40
|
|
37.5 -
40
|
|
Capitalized G&A
and Interest
|
25
|
|
25
|
Total Other
Exploration and Production
|
$95 -
$110
|
|
$92.5 -
$102.5
|
|
|
|
|
|
|
|
|
General
Corporate
|
$5
|
|
$5
|
Total Capital
Expenditures (excluding acquisitions and abandonment
liabilities)
|
$225 -
$255
|
|
$220 -
$240
|
|
|
|
|
|
|
|
1)
|
May be materially
affected at year end by application of Fresh Start
accounting.
|
2)
|
Adjusted
G&A - Cash is a non-GAAP financial measure as it excludes
from G&A non-cash compensation, severance, bad debt allowance,
shareholder litigation costs, restructuring costs, and other
non-recurring items. Incentive compensation plan normalized to be
consistent with prior year compensation plans. 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.
|
3)
|
2015 Carryover, JV
Penalty, Rig Penalty, Non-Op, SWD
|
4)
|
Facilities -
Electrical, SWD, Gathering, Pipelines
|
|
|
|
SandRidge Energy,
Inc. and Subsidiaries (Debtor-in-Possession)
|
Condensed
Consolidated Statements of Operations
|
(In
thousands)
|
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
(unaudited)
|
Revenues
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and
NGL
|
$
99,934
|
|
$
165,135
|
|
$
279,971
|
|
$
575,399
|
|
Midstream and
marketing
|
3,004
|
|
8,838
|
|
10,545
|
|
26,208
|
|
Drilling and
services
|
886
|
|
4,572
|
|
2,342
|
|
19,658
|
|
Other
|
232
|
|
1,607
|
|
951
|
|
3,802
|
|
|
Total
revenues
|
104,056
|
|
180,152
|
|
293,809
|
|
625,067
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
Production
|
39,640
|
|
72,884
|
|
129,608
|
|
244,158
|
|
Production
taxes
|
2,278
|
|
3,652
|
|
6,107
|
|
12,548
|
|
Cost of
sales
|
563
|
|
4,323
|
|
5,302
|
|
22,034
|
|
Midstream and
marketing
|
-
|
|
6,633
|
|
1,840
|
|
22,464
|
|
Depreciation and
depletion - oil and natural gas
|
26,335
|
|
66,501
|
|
86,613
|
|
266,906
|
|
Depreciation and
amortization - other
|
7,514
|
|
11,379
|
|
21,323
|
|
37,234
|
|
Accretion of asset
retirement obligations
|
1,390
|
|
1,132
|
|
4,365
|
|
3,323
|
|
Impairment
|
354,451
|
|
1,074,588
|
|
718,194
|
|
3,647,845
|
|
General and
administrative
|
29,145
|
|
34,233
|
|
134,447
|
|
108,764
|
|
(Gain) loss on
derivative contracts
|
(338)
|
|
(42,211)
|
|
4,823
|
|
(59,034)
|
|
Loss on settlement of
contract
|
-
|
|
-
|
|
90,184
|
|
-
|
|
Loss (gain) on sale
of assets
|
416
|
|
6,771
|
|
(2,794)
|
|
2,097
|
|
|
Total
expenses
|
461,394
|
|
1,239,885
|
|
1,200,012
|
|
4,308,339
|
|
|
Loss from
operations
|
(357,338)
|
|
(1,059,733)
|
|
(906,203)
|
|
(3,683,272)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (expense)
income
|
|
|
|
|
|
|
|
|
Interest expense
(excludes $36.9 million and $74.5 million of contractual
interest expense on debt subject to
compromise for the three and nine-month
periods ended September 30, 2016,
respectively)
|
(3,343)
|
|
(77,000)
|
|
(126,099)
|
|
(213,569)
|
|
Gain on
extinguishment of debt
|
-
|
|
340,699
|
|
41,179
|
|
358,633
|
|
Reorganization items,
net
|
(42,754)
|
|
-
|
|
(243,672)
|
|
-
|
|
Other (expense)
income, net
|
(898)
|
|
(426)
|
|
1,332
|
|
1,208
|
|
|
Total other (expense)
income
|
(46,995)
|
|
263,273
|
|
(327,260)
|
|
146,272
|
Loss before income
taxes
|
(404,333)
|
|
(796,460)
|
|
(1,233,463)
|
|
(3,537,000)
|
Income tax
expense
|
4
|
|
25
|
|
11
|
|
90
|
Net loss
|
|
|
(404,337)
|
|
(796,485)
|
|
(1,233,474)
|
|
(3,537,090)
|
|
Less: net loss
attributable to noncontrolling interest
|
-
|
|
(156,073)
|
|
-
|
|
(493,243)
|
Net loss attributable
to SandRidge Energy, Inc.
|
(404,337)
|
|
(640,412)
|
|
(1,233,474)
|
|
(3,043,847)
|
Preferred stock
dividends
|
-
|
|
9,114
|
|
16,321
|
|
27,069
|
|
|
Loss applicable to
SandRidge Energy, Inc.
common
stockholders
|
|
|
|
|
|
|
|
|
|
$
(404,337)
|
|
$
(649,526)
|
|
$
(1,249,795)
|
|
$
(3,070,916)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SandRidge Energy,
Inc. and Subsidiaries (Debtor-in-Possession)
|
Condensed
Consolidated Balance Sheets
|
(In
thousands)
|
|
|
|
|
|
|
|
September
30,
|
|
December
31,
|
|
2016
|
|
2015
|
|
|
|
|
|
|
(unaudited)
|
ASSETS
|
|
Current
assets
|
|
|
|
|
Cash and cash
equivalents
|
$
652,680
|
|
$
435,588
|
Accounts receivable,
net
|
61,446
|
|
127,387
|
Derivative
contracts
|
10,192
|
|
84,349
|
Prepaid
expenses
|
|
12,514
|
|
6,833
|
Other current
assets
|
1,003
|
|
19,931
|
|
|
Total current
assets
|
|
737,835
|
|
674,088
|
Oil and natural gas
properties, using full cost method of accounting
|
|
|
|
|
Proved
|
12,093,492
|
|
12,529,681
|
|
Unproved
|
322,580
|
|
363,149
|
|
Less: accumulated
depreciation, depletion and impairment
|
(11,637,538)
|
|
(11,149,888)
|
|
|
|
|
|
|
778,534
|
|
1,742,942
|
Other property, plant
and equipment, net
|
|
357,528
|
|
491,760
|
Derivative
contracts
|
|
70
|
|
-
|
Other
assets
|
|
12,537
|
|
13,237
|
|
|
Total
assets
|
|
$
1,886,504
|
|
$
2,922,027
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
|
Current
liabilities
|
|
|
|
|
Accounts payable and
accrued expenses
|
|
$
140,448
|
|
$
428,417
|
Derivative
contracts
|
2,982
|
|
573
|
Asset retirement
obligations
|
8,573
|
|
8,399
|
|
|
Total current
liabilities
|
|
152,003
|
|
437,389
|
Long-term
debt
|
|
-
|
|
3,562,378
|
Derivative
contracts
|
|
935
|
|
-
|
Asset retirement
obligations
|
|
62,896
|
|
95,179
|
Other long-term
obligations
|
|
3
|
|
14,814
|
Liabilities subject
to compromise
|
|
4,346,188
|
|
-
|
|
|
Total
liabilities
|
|
4,562,025
|
|
4,109,760
|
Commitments and
contingencies
|
|
|
|
|
Equity
(deficit)
|
|
|
|
|
SandRidge Energy,
Inc. stockholders' equity (deficit)
|
|
|
|
Preferred stock,
$0.001 par value, 50,000 shares authorized
|
|
|
|
|
8.5% Convertible
perpetual preferred stock; 2,650 shares issued and outstanding
at
|
|
|
|
|
September 30,
2016 and December 31, 2015; aggregate liquidation preference of
$265,000
|
3
|
|
3
|
|
7.0% Convertible
perpetual preferred stock; 2,597 shares issued and outstanding
at
|
|
|
|
|
September 30,
2016: aggregate liquidation preference of $259,700; 2,770 shares
issued
|
|
|
|
|
and outstanding
at December 31, 2015: aggregate liquidation preference of
$277,000
|
3
|
|
3
|
|
Common stock, $0.001
par value; 1,800,000 shares authorized; 720,936 issued
and
|
|
|
|
|
719,425 outstanding
at September 30, 2016 and 635,584 issued and 633,471 outstanding
at
|
|
|
|
|
December 31,
2015
|
|
718
|
|
630
|
Additional paid-in
capital
|
5,315,655
|
|
5,301,136
|
Additional paid-in
capital - stockholder receivable
|
(1,250)
|
|
(1,250)
|
Treasury stock, at
cost
|
(5,218)
|
|
(5,742)
|
Accumulated
deficit
|
(7,985,411)
|
|
(6,992,697)
|
|
|
Total SandRidge
Energy, Inc. stockholders' deficit
|
(2,675,500)
|
|
(1,697,917)
|
Noncontrolling
interest
|
|
(21)
|
|
510,184
|
|
|
Total stockholders'
deficit
|
|
(2,675,521)
|
|
(1,187,733)
|
|
|
Total liabilities and
stockholders' deficit
|
|
$
1,886,504
|
|
$
2,922,027
|
|
|
|
|
|
|
|
|
|
SandRidge Energy,
Inc. and Subsidiaries (Debtor-in-Possession)
|
Condensed
Consolidated Statements of Cash Flows
|
(In
thousands)
|
|
|
|
|
|
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
(unaudited)
|
CASH FLOWS FROM
OPERATING ACTIVITIES
|
|
|
|
|
Net loss
|
$
(1,233,474)
|
|
$
(3,537,090)
|
|
Adjustments to
reconcile net loss to net cash (used in) provided by operating
activities
|
|
|
|
|
|
Provision for
doubtful accounts
|
|
16,704
|
|
-
|
|
|
Depreciation,
depletion and amortization
|
|
107,936
|
|
304,140
|
|
|
Accretion of asset
retirement obligations
|
|
4,365
|
|
3,323
|
|
|
Impairment
|
|
718,194
|
|
3,647,845
|
|
|
Reorganization items,
net
|
|
231,836
|
|
-
|
|
|
Debt issuance costs
amortization
|
|
4,996
|
|
8,324
|
|
|
Amortization of
discount, net of premium, on debt
|
2,734
|
|
1,053
|
|
|
Gain on
extinguishment of debt
|
|
(41,179)
|
|
(358,633)
|
|
|
Write off of debt
issuance costs
|
|
-
|
|
7,108
|
|
|
Gain on debt
derivatives
|
|
(1,324)
|
|
(10,146)
|
|
|
Cash paid for early
conversion of convertible notes
|
(33,452)
|
|
(2,708)
|
|
|
Loss (gain) on
derivative contracts
|
|
4,823
|
|
(59,034)
|
|
|
Cash received on
settlement of derivative contracts
|
72,608
|
|
278,581
|
|
|
Loss on settlement of
contract
|
|
90,184
|
|
-
|
|
|
Cash paid on
settlement of contract
|
|
(11,000)
|
|
-
|
|
|
(Gain) loss on sale
of assets
|
|
(2,794)
|
|
2,097
|
|
|
Stock-based
compensation
|
|
9,075
|
|
15,170
|
|
|
Other
|
|
(466)
|
|
1,772
|
|
|
Changes in operating
assets and liabilities
|
(3,805)
|
|
59,084
|
|
|
|
|
Net cash (used in)
provided by operating activities
|
(64,039)
|
|
360,886
|
CASH FLOWS FROM
INVESTING ACTIVITIES
|
|
|
|
|
Capital expenditures
for property, plant and equipment
|
(186,452)
|
|
(761,905)
|
|
Acquisition of
assets
|
|
(1,328)
|
|
(3,231)
|
|
Proceeds from sale of
assets
|
|
20,090
|
|
35,387
|
|
|
|
|
Net cash used in
investing activities
|
|
(167,690)
|
|
(729,749)
|
CASH FLOWS FROM
FINANCING ACTIVITIES
|
|
|
|
|
Proceeds from
borrowings
|
|
489,198
|
|
2,190,000
|
|
Repayments of
borrowings
|
|
(40,000)
|
|
(1,034,466)
|
|
Debt issuance
costs
|
|
(333)
|
|
(48,021)
|
|
Noncontrolling
interest distributions
|
|
-
|
|
(115,301)
|
|
Purchase of treasury
stock
|
|
(44)
|
|
(3,198)
|
|
Dividends paid -
preferred
|
|
-
|
|
(11,262)
|
|
|
|
|
Net cash provided by
financing activities
|
448,821
|
|
977,752
|
NET INCREASE IN CASH
AND CASH EQUIVALENTS
|
217,092
|
|
608,889
|
CASH AND CASH
EQUIVALENTS, beginning of year
|
435,588
|
|
181,253
|
CASH AND CASH
EQUIVALENTS, end of period
|
$
652,680
|
|
$
790,142
|
|
|
|
|
|
|
|
|
|
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
|
$
25,045
|
|
$
160,853
|
|
Equity issued for
debt
|
|
$
4,409
|
|
$
(35,147)
|
|
Preferred stock
dividends paid in common stock
|
$
-
|
|
$
(16,188)
|
Non-GAAP Financial Measures
Adjusted operating cash flow, adjusted EBITDA, pro forma
adjusted EBITDA and adjusted net loss 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.
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 tables below reconcile the most directly comparable GAAP
financial measures to operating cash flow, EBITDA and adjusted
EBITDA and adjusted net loss.
Reconciliation of
Cash Provided by (Used in) Operating Activities to Adjusted
Operating Cash Flow
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
(used in) operating activities
|
|
$
75,002
|
|
$
41,892
|
|
$
(64,039)
|
|
$
360,886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in operating
assets and liabilities
|
|
(43,215)
|
|
2,673
|
|
3,805
|
|
(59,084)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted operating
cash flow
|
|
$
31,787
|
|
$
44,565
|
|
$
(60,234)
|
|
$
301,802
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
Net Loss to EBITDA and Adjusted EBITDA
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
(404,337)
|
|
$
(640,412)
|
|
$
(1,233,474)
|
|
$
(3,043,847)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
for
|
|
|
|
|
|
|
|
|
|
Income tax
expense
|
|
4
|
|
25
|
|
11
|
|
90
|
|
Interest
expense
|
|
3,589
|
|
77,501
|
|
127,517
|
|
214,198
|
|
Depreciation and
amortization - other
|
|
7,514
|
|
11,379
|
|
21,323
|
|
37,234
|
|
Depreciation and
depletion - oil and natural gas
|
|
26,335
|
|
66,501
|
|
86,613
|
|
266,906
|
|
Accretion of asset
retirement obligations
|
|
1,390
|
|
1,132
|
|
4,365
|
|
3,323
|
EBITDA
|
|
(365,505)
|
|
(483,874)
|
|
(993,645)
|
|
(2,522,096)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset
impairment
|
|
354,451
|
|
1,074,588
|
|
718,194
|
|
3,647,845
|
|
Interest
income
|
|
(246)
|
|
(501)
|
|
(1,418)
|
|
(629)
|
|
Stock-based
compensation
|
|
1,247
|
|
3,203
|
|
4,291
|
|
9,294
|
|
(Gain) loss on
derivative contracts
|
|
(338)
|
|
(42,211)
|
|
4,823
|
|
(59,034)
|
|
Cash received upon
settlement of derivative contracts (1)
|
|
20,393
|
|
67,258
|
|
66,851
|
|
278,581
|
|
Loss on settlement of
contract
|
|
-
|
|
-
|
|
90,184
|
|
-
|
|
Loss (gain) on sale
of assets
|
|
416
|
|
6,771
|
|
(2,794)
|
|
2,097
|
|
Legal
settlement
|
|
-
|
|
5,122
|
|
-
|
|
4,994
|
|
Severance
|
|
55
|
|
1,290
|
|
17,541
|
|
11,819
|
|
Oil field services -
exit costs
|
|
12
|
|
62
|
|
2,428
|
|
4,353
|
|
Gain on
extinguishment of debt
|
|
-
|
|
(340,699)
|
|
(41,179)
|
|
(358,633)
|
|
Restructuring
costs
|
|
421
|
|
-
|
|
18,865
|
|
-
|
|
Reorganization items,
net
|
|
42,754
|
|
-
|
|
243,672
|
|
-
|
|
Employee incentive
and retention
|
|
9,724
|
|
-
|
|
20,141
|
|
-
|
|
Other
|
|
1,351
|
|
935
|
|
19,032
|
|
3,676
|
|
Non-cash portion of
noncontrolling interest (2)
|
|
-
|
|
(174,304)
|
|
-
|
|
(561,969)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA
|
|
$
64,735
|
|
$
117,640
|
|
$
166,986
|
|
$
460,298
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: EBITDA
attributable to WTO properties (2016)
|
|
-
|
|
16,644
|
|
1,990
|
|
49,502
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma adjusted
EBITDA
|
|
$
64,735
|
|
$
134,284
|
|
$
168,976
|
|
$
509,800
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 Provided by (Used in) Operating Activities to Adjusted
EBITDA
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
(used in) operating activities
|
|
$
75,002
|
|
$
41,892
|
|
$
(64,039)
|
|
$
360,886
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in operating
assets and liabilities
|
|
(43,215)
|
|
2,673
|
|
3,805
|
|
(59,084)
|
Interest
expense
|
|
3,589
|
|
77,501
|
|
127,517
|
|
214,199
|
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
|
|
-
|
|
2,709
|
|
33,452
|
|
2,709
|
Cash paid on
settlement of contract
|
|
-
|
|
-
|
|
11,000
|
|
-
|
Legal
settlements
|
|
-
|
|
5,122
|
|
-
|
|
4,994
|
Severance
(1)
|
|
77
|
|
1,156
|
|
12,463
|
|
7,004
|
Oil field services -
exit costs (1)
|
|
13
|
|
62
|
|
2,386
|
|
4,275
|
Restructuring
costs
|
|
421
|
|
-
|
|
18,865
|
|
-
|
Cash paid for
reorganization items
|
|
11,836
|
|
-
|
|
11,836
|
|
-
|
Employee incentive
and retention
|
|
9,724
|
|
-
|
|
20,141
|
|
-
|
Noncontrolling
interest - SDT (2)
|
|
-
|
|
(6,619)
|
|
-
|
|
(19,237)
|
Noncontrolling
interest - SDR (2)
|
|
-
|
|
(4,918)
|
|
-
|
|
(16,277)
|
Noncontrolling
interest - PER (2)
|
|
-
|
|
(6,694)
|
|
-
|
|
(33,212)
|
Other
|
|
|
1,532
|
|
4,756
|
|
(4,683)
|
|
(5,959)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA
|
|
$
64,735
|
|
$
117,640
|
|
$
166,986
|
|
$
460,298
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 Loss Applicable to Common Stockholders to Adjusted Net
Income Available (Loss Applicable) to Common
Stockholders
|
|
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss applicable to
common stockholders
|
|
$
(404,337)
|
|
$
(649,526)
|
|
$
(1,249,795)
|
|
$
(3,070,916)
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset impairment
(1)
|
|
354,451
|
|
907,834
|
|
718,194
|
|
3,127,684
|
(Gain) loss on
derivative contracts (1)
|
|
(338)
|
|
(38,438)
|
|
4,823
|
|
(53,926)
|
Cash received upon
settlement of derivative contracts (1)(2)
|
|
20,393
|
|
60,342
|
|
66,851
|
|
249,665
|
Loss on settlement of
contract
|
|
-
|
|
-
|
|
90,184
|
|
-
|
Loss (gain) on sale
of assets
|
|
416
|
|
6,771
|
|
(2,794)
|
|
2,097
|
Legal
settlements
|
|
-
|
|
5,122
|
|
-
|
|
4,994
|
Severance
|
|
55
|
|
1,290
|
|
17,541
|
|
11,819
|
Oil field services -
exit costs
|
|
12
|
|
62
|
|
2,428
|
|
4,353
|
Gain on
extinguishment of debt
|
|
-
|
|
(340,699)
|
|
(41,179)
|
|
(358,633)
|
Restructuring
costs
|
|
421
|
|
-
|
|
18,865
|
|
-
|
Reorganization items,
net
|
|
42,754
|
|
-
|
|
243,672
|
|
-
|
Employee incentive
and retention
|
|
9,724
|
|
-
|
|
20,141
|
|
-
|
Other
|
|
|
1,780
|
|
(10,306)
|
|
18,194
|
|
(8,243)
|
Effect of income
taxes
|
|
4
|
|
19
|
|
10
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income
available (loss applicable) to common stockholders
|
|
25,335
|
|
(57,529)
|
|
(92,865)
|
|
(91,030)
|
Preferred stock
dividends (3)
|
|
-
|
|
9,114
|
|
-
|
|
27,069
|
Effect of convertible
debt, net of income taxes (3)
|
|
-
|
|
2,918
|
|
-
|
|
2,918
|
|
|
|
|
|
|
|
|
|
|
|
|
Total adjusted net
income (loss)
|
|
$
25,335
|
|
$
(45,497)
|
|
$
(92,865)
|
|
$
(61,043)
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
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, net income and
EBITDA, 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, efficiency and cost reduction initiative
outcomes, infrastructure utilization and 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.
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/sandridge-energy-inc-updates-shareholders-on-operations-and-reports-financial-results-for-third-quarter-and-first-nine-months-of-2016-300359357.html
SOURCE SandRidge Energy, Inc.