From the Wires
SandRidge Energy, Inc. Reports Financial and Operational Results for Third Quarter and First Nine Months of 2008
Nov. 6, 2008 04:05 PM
OKLAHOMA CITY, Nov. 6 /PRNewswire-FirstCall/ -- SandRidge Energy, Inc.
(NYSE: SD) today announced financial and operational results for the quarter
and nine months ended September 30, 2008.
Financial Highlights
Third Quarter
-- Net income available to common stockholders increased to $230.3
million, or $1.40 per share fully diluted, compared to $11.6 million, or $0.11
per share fully diluted, in third quarter 2007
-- Adjusted net income available to common stockholders (which excludes
unrealized non-cash gains on derivative contracts) was $28.0 million, or $0.17
per share fully diluted, in third quarter 2008 compared to an adjusted net
loss applicable to common stockholders of $0.7 million, or $0.01 per share
fully diluted, in third quarter 2007
-- Operating cash flow increased 87% to $137.2 million from $73.3 million
in third quarter 2007
-- Adjusted EBITDA increased 75% to $179.6 million from $102.6 million in
third quarter 2007
First Nine Months
-- Net income available to common stockholders increased to $137.1
million, or $0.89 per share fully diluted, compared to $5.4 million, or $0.05
per share fully diluted, in the nine months ended September 30, 2007
-- Adjusted net income available to common stockholders (which excludes
unrealized non-cash gains on derivative contracts) was $85.6 million, or $0.55
per share fully diluted, in the nine months ended September 30, 2008 compared
to an adjusted net loss applicable to common stockholders of $17.4 million, or
$0.17 per share fully diluted, in the nine months ended September 30, 2007
-- Operating cash flow increased 128% to $425.6 million from $186.4
million in the nine months ended September 30, 2007
-- Adjusted EBITDA increased 104% to $530.2 million from $260.2 million
in the nine months ended September 30, 2007
Adjusted net income available (loss applicable) to common stockholders,
operating cash flow and adjusted EBITDA are non-GAAP financial measures. Each
measure is defined and reconciled to the most directly comparable GAAP measure
under "Non-GAAP Financial Measures" beginning on page 10.
Operational Highlights and Production Guidance:
-- Current daily production of 305 MMcfe, with an additional 20 MMcfe per
day shut in
-- Third quarter 2008 natural gas and crude oil production of 25.3 Bcfe
(275 MMcfe per day) remained consistent with second quarter 2008 despite
temporary shut-ins of approximately 3.0 Bcfe during third quarter 2008 and
increased 58% compared to third quarter 2007
-- First nine months 2008 natural gas and crude oil production of 73.6
Bcfe (269 MMcfe per day) increased 68% compared to production of 43.8 Bcfe in
the first nine months of 2007
-- Proved reserves at September 30, 2008 of 2.143 Tcfe increased 12% from
June 30, 2008, 42% from December 31, 2007 and 68% from September 30, 2007
-- West Texas Overthrust ("WTO") leasehold position increased to
approximately 657,000 net acres at September 30, 2008 from approximately
610,000 net acres at June 30, 2008 and 509,000 net acres at December 31, 2007
-- Drilling finding costs and all-in finding costs were $1.60 and $2.26
per Mcfe, respectively, in third quarter 2008 and $1.49 and $1.94 per Mcfe,
respectively, in the first nine months of 2008
-- 2008 net production guidance (issued May 2008) of 100.0 Bcfe remains
unchanged despite expected net production loss of approximately 5.5 Bcfe in
the second half of 2008
Presentation slides to be viewed in conjunction with certain of the above
Operational Highlights are available on the company's website,
http://www.sandridgeenergy.com, under Investor Relations/Events.
Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
Production:
Natural gas (MMcf) 22,209 12,856 63,097 35,148
Crude oil (MBbl)(1) 521 535 1,751 1,441
Natural gas equivalent (MMcfe) 25,335 16,067 73,603 43,793
Daily Production (MMcfed) 275 175 269 160
Average price per unit:
Realized natural gas price per Mcf -
as reported $9.04 $5.99 $9.09 $6.56
Realized impact of derivatives per Mcf (0.95) 1.55 (0.99) 0.55
Net realized price per Mcf $8.09 $7.54 $8.10 $7.11
Realized crude oil price per barrel -
as reported (1) $112.24 $67.57 $104.73 $61.67
Realized impact of derivatives per
barrel (1) (12.05) - (9.07) -
Net realized price per barrel (1) $100.19 $67.57 $95.66 $61.67
Realized price per Mcfe - as reported $10.23 $7.04 $10.28 $7.30
Net realized price per Mcfe -
including impact of derivatives per
Mcfe $9.15 $8.28 $9.22 $7.73
Average cost per Mcfe:
Lease operating $1.62 $1.79 $1.57 $1.77
Production taxes 0.27 0.27 0.40 0.28
General and administrative:
General and administrative,
excluding stock-based compensation 0.88 1.10 0.84 0.93
Stock-based compensation 0.28 0.17 0.19 0.11
Depletion 2.84 2.81 2.84 2.65
Lease operating cost per Mcfe:
Excluding offshore and tertiary
recovery $1.42 $1.55 $1.37 $1.50
Offshore operations 4.35 3.06 3.74 3.17
Tertiary recovery operations 11.67 12.80 11.28 12.10
Earnings per share:
Income per share available to common
stockholders
Basic $1.41 $0.11 $0.90 $0.05
Diluted 1.40 0.11 0.89 0.05
Basic and diluted adjusted net income
(loss) available (applicable)
to common stockholders 0.17 (0.01) 0.56 (0.17)
Weighted average number of common
shares outstanding (thousands)
Basic 163,020 107,554 153,125 102,562
Diluted 164,554 109,049 154,489 103,778
(1) Includes NGLs
Financial Results
Third Quarter
Net income available to common stockholders for the three months ended
September 30, 2008 rose to $230.3 million, or $1.40 per share fully diluted,
from $11.6 million, or $0.11 per share fully diluted, for the same period in
2007. The increase was driven primarily by a combination of increases in
production and prices received for production, a decrease in cost per unit
produced and an increase in non-cash mark-to-market gains on derivative
contracts. Excluding unrealized gains on natural gas and crude oil
derivatives, which are detailed below, SandRidge had adjusted net income
available to common stockholders of $28.0 million, or $0.17 per share fully
diluted, in third quarter 2008 compared to an adjusted net loss applicable to
common stockholders of $0.7 million, or $0.01 per share fully diluted, in
third quarter 2007. The company generated operating cash flow of $137.2
million in third quarter 2008, compared to $73.3 million in third quarter
2007, and adjusted EBITDA of $179.6 million in third quarter 2008, compared to
$102.6 million in third quarter 2007.
The increase in total production combined with the increase in prices
received for production resulted in higher natural gas and crude oil revenues
of $259.1 million for third quarter 2008 compared to $113.1 million for third
quarter 2007. Total natural gas production increased 73% to 22.2 Bcf in third
quarter 2008 from 12.9 Bcf in the same period in 2007 as a result of the
company's continued drilling success and increased ownership in the WTO. Crude
oil production decreased slightly to 521 MBbls in third quarter 2008 from 535
MBbls in third quarter 2007 due to hurricane-related production shut-ins.
The average price received, excluding the impact of derivative contract
settlements, for natural gas sales increased 51% in the three months ended
September 30, 2008 to $9.04 per Mcf compared to $5.99 per Mcf in the same
period in 2007. The average price received, excluding the impact of derivative
contract settlements, for crude oil production increased 66%, or $44.67 per
barrel, to $112.24 per barrel during third quarter 2008 from $67.57 per barrel
during the same period in 2007.
Total production expense increased to $41.1 million during the three
months ended September 30, 2008 from $28.7 million during the same period in
2007. Production expense on a per Mcfe basis, however, decreased 10% during
third quarter 2008 to an average cost of $1.62 per Mcfe compared to $1.79 per
Mcfe during the 2007 period. This decrease in expense per unit, combined with
higher average prices received for production, allowed the company to enjoy
larger operating margins in its core exploration and production segment during
third quarter 2008 compared to the same period in 2007.
The company enters into natural gas and crude oil swaps and basis swaps
for a portion of its production in order to stabilize future cash inflows for
planning purposes. In that regard, net income for the three months ended
September 30, 2008, was increased by a net gain of $292.5 million ($319.8
million unrealized gain and $27.3 million realized loss) on derivative
contracts. This compares to a $39.2 million gain ($19.3 million unrealized
gain and $19.9 million realized gain) for the same period in 2007.
Production and Drilling Activities
SandRidge owned working interests in 2,075 producing wells at September
30, 2008 compared to 1,523 producing wells at September 30, 2007. The company
had an average of 45 rigs operating on its properties during the third quarter
of 2008. Daily production averaged 275 MMcfe during the third quarter 2008 and
currently is approximately 305 MMcfe, with an additional 20 MMcfe per day shut
in. The company entered the third quarter with 25 MMcfe per day shut in due
to the shut down of the Grey Ranch Plant in Pecos County, Texas following a
fire on June 27, 2008 and well work in the Gulf Coast. During the quarter, the
company's production was also impacted by hurricanes Gustav and Ike. The
resulting total production loss was approximately 3.0 Bcfe for third quarter
2008. An additional 2.5 Bcfe in production loss is expected for fourth quarter
2008. The Grey Ranch Plant was placed back in service on November 1, 2008, and
other significant production curtailments related to the hurricanes are
expected to be resolved by mid-December 2008. Despite the projected production
loss in the second half of 2008, the company expects to meet its full-year
production guidance of 100.0 Bcfe as issued in May 2008.
The following is an operational update for each of the company's key
areas:
West Texas Overthrust (WTO): The company averaged 34 rigs operating in the
WTO drilling 76 wells during third quarter 2008. There are currently 27 rigs
active in the WTO. The company expects to exit 2008 with 20 active rigs in
this area. A total of 60 gross (57 net) wells were completed and brought on
production in the WTO during third quarter 2008. At September 30, 2008, the
company owned and operated 612 gross (572 net) wells in the WTO.
SandRidge acquired 265 square miles of 3-D seismic data in the third
quarter of 2008 bringing the total 3-D seismic acquired to date in the WTO to
1,115 square miles. SandRidge continues to exploit and expand the Pinon field
utilizing 3-D data and well control to identify new reservoirs in the three
primary thrusts (Dugout Creek, Warwick, and Frog Creek). SandRidge expects to
have 1,250 square miles of the planned 1,500 square mile 3-D seismic shoot
completed by year-end 2008.
With the aid of 3-D seismic data and well control, SandRidge believes it
can high-grade its drilling locations in the multiple thrusts within the Pinon
field and continue to deliver drilling finding costs below $1.70 per Mcfe. The
5.1 Tcfe of net proved, possible and probable reserves identified in the Pinon
field are located almost exclusively in the Dugout Creek and Warwick thrusts.
The Frog Creek thrust is the most recent of the three thrusts discovered in
the Pinon field to have commercial production and provides drilling
opportunities in the Caballos chert at depths ranging from 3,500 feet to 5,500
feet. The Frog Creek thrust as interpreted by 3-D data appears to be similar
in size to that of the Dugout Creek and Warwick thrusts. Recent production
tests from the Frog Creek thrust confirm low (less than 3%) CO2 gas. The
company believes the Frog Creek thrust may contain substantial quantities of
reserves that can be developed at or below current Pinon drilling finding
costs.
High CO2 Gas Update: The most prolific reservoir in the Pinon field is the
Warwick Caballos Chert high CO2 reservoir at depths of 6,000 feet to 8,000
feet. The average estimated ultimate recovery per well for this reservoir from
approximately 125 wells drilled to date is 7.0 Bcfe of total gas. The expected
drilling finding cost for the Warwick Caballos is $1.05 per Mcfe of methane.
Production from this reservoir is currently limited to approximately 150.0
MMcf per day of inlet high CO2 gas processing capacity of the company's legacy
plants. The company is in the process of expanding the capacity of existing
plants as well as constructing the new Century Plant. The Century Plant is
designed to have processing capacity of 800.0 MMcf per day and is expected to
be completed in two phases with the first phase coming on line second quarter
2010 and the second phase coming on line second quarter 2011. Methane
production from the Warwick thrust high CO2 reservoir is expected to develop
as follows (volumes in MMcf per day):
Plant Approximate Approximate
Inlet Gross SandRidge
Date Capacity Methane Net Methane Plant Source
Current 150 55 40 Existing Plants
YE 2008 300 105 77 Existing Plants
Q1 2009 350 120 88 Existing Plants
Q2 2010 750 260 190 Existing + Century Phase 1
Q2 2011 1,150 400 290 Existing + Century Phase 2
Given the current limited availability of CO2 treating capacity, the risk
of finding gas containing CO2 at levels above pipeline specifications limits
the company's ability to aggressively develop the Warwick thrust. Once the
Century Plant commences operations in 2010, the company intends to implement a
more aggressive drilling program and accelerate production and reserves growth
from the Warwick thrust.
East Texas: The company averaged 4 rigs operating on the company's
properties in East Texas drilling 11 wells during third quarter 2008. A total
of 14 gross (14 net) wells were completed and brought on production in East
Texas during third quarter 2008. At September 30, 2008, the company owned 223
gross (208 net) wells in East Texas.
Mid-Continent: The company averaged 5 rigs operating on its prospects
located in Oklahoma drilling 38 wells during third quarter 2008. A total of 35
gross (18 net) Oklahoma wells were completed and brought on production in
third quarter 2008. At September 30, 2008, the company owned 569 gross (212
net) wells in the Mid-Continent area.
Capital Expenditures
The table below summarizes the company's capital expenditures for the
three- and nine-month periods ended September 30, 2008 and 2007:
Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
(in thousands) (in thousands)
Drilling and production
WTO $261,056 $185,027 $750,883 $373,510
Non-WTO (excluding tertiary) 118,139 57,430 273,330 134,711
Tertiary 9,395 8,265 18,764 17,341
388,590 250,722 1,042,977 525,562
Leasehold and seismic
WTO 116,350 53,302 232,940 135,834
Non-WTO (excluding tertiary) 62,228 23,841 104,472 40,275
Tertiary 3 752 87 2,501
178,581 77,895 337,499 178,610
Pipe Inventory 22,220 - 22,220 -
Total exploration and
development 589,391 328,617 1,402,696 704,172
Drilling and oil field services 25,749 20,883 61,540 104,796
Midstream 40,696 22,297 110,125 45,427
Other - general 19,218 31,219 34,994 40,765
Total capital expenditures $675,054 $403,016 $1,609,355 $895,160
Third quarter 2008 exploration and development expenditures of $589.4
million were 79% higher than third quarter 2007 exploration and development
expenditures as the company continued to ramp up drilling activity in its key
operating areas, gather and process WTO 3-D seismic data, and acquire
leasehold positions in its core development areas. The company's midstream
business incurred capital expenditures of $40.7 million during third quarter
2008 compared to $22.3 million during the same period in 2007 as the company
continued to build pipeline infrastructure and add compression in the WTO.
Proved Reserves
The company's estimated proved reserves as of September 30, 2008 were
2.143 Tcfe, representing a 12% increase from June 30, 2008 proved reserves of
1.918 Tcfe and a 42% increase from December 31, 2007 proved reserves of 1.516
Tcfe. Quarterly 2008 estimates of proved reserves were internally prepared and
have not been reviewed by third-party engineers. Drilling finding costs were
$1.60 per Mcfe and $1.49 per Mcfe for the three- and nine-month periods ended
September 30, 2008, respectively. The all-in finding costs, which include
drilling, acquisitions, land, and seismic costs, were $2.26 per Mcfe and $1.94
per Mcfe for the three- and nine-month periods ended September 30, 2008,
respectively. Proved developed reserves constituted 46% of total reserves as
of September 30, 2008 and June 30, 2008 and 44% at December 31, 2007. The
September 30, 2008 estimated future net cash flows from proved reserves,
discounted at an annual rate of 10% before income taxes ("PV-10") were $6.40
billion, a decrease of 40% from June 30, 2008 PV-10 of $10.61 billion and an
increase of 80% from December 31, 2007 PV-10 of $3.55 billion.
Decreases in price per unit of future production accounted for $4.75
billion, or 113%, of the total net decrease in PV-10 from June 30, 2008 to
September 30, 2008. The calculated weighted average per unit prices for the
company's proved reserves and future net revenues were $8.08 per Mcf for
natural gas and $99.23 per barrel for crude oil at September 30, 2008 compared
to $12.98 per Mcf for natural gas and $130.68 per barrel for crude oil at June
30, 2008 and $6.46 per Mcf for natural gas and $87.47 per barrel for crude oil
at December 31, 2007.
On an after-tax basis (SFAS 69 standardized measure), such 2007 year-end
future net cash flows were $2.72 billion. The company calculates the
standardized measure of future net cash flows in accordance with SFAS 69 only
at year end because applicable income tax information on properties, including
recently acquired natural gas and oil interests, is not readily available at
other times during the year. As a result, the company is not able to
reconcile the interim period-end values to the standardized measure at such
dates. The only difference between the two measures is that PV-10 is
calculated before considering the impact of future income tax expenses, while
the standardized measure includes such effects.
Analysis of Changes in Proved Reserves
Crude Oil Natural Gas Combined
(MBbls) (Bcf) (Bcfe)
As of December 31, 2007 36,527 1,297 1,516
Revisions of previous estimates 2,728 125 141
Acquisitions of new reserves 3 1 2
Sales of reserves in place - - -
Extensions and discoveries 412 61 63
Production (611) (19) (23)
As of March 31, 2008 39,059 1,465 1,699
Revisions of previous estimates 7,141 105 148
Acquisitions of new reserves - - -
Sales of reserves in place (66) (10) (10)
Extensions and discoveries 234 106 107
Production (620) (22) (26)
As of June 30, 2008 45,748 1,644 1,918
Revisions of previous estimates 4,471 154 181
Acquisitions of new reserves 358 6 8
Sales of reserves in place - - -
Extensions and discoveries 1,353 53 61
Production (521) (22) (25)
As of September 30, 2008 51,409 1,835 2,143
Reserve Replacement Economics
Nine
Quarter Months
3 - Ended Ended
Year Sept. 30, Sept. 30,
2005 2006 2007 Average 2008 2008
(in millions except as noted)
Proved reserves
(Bcfe) 300.0 1,001.8 1,516.2 2,143.2 2,143.2
% Proved reserve
growth 102% 234% 51% 12% 42%
% Proved
developed 25% 32% 44% 46% 46%
Annual
Production
(Bcfe) 7.3 15.3 64.2 28.9 n/m n/m
% Production
growth 2% 110% 320% 41.4(1) n/m n/m
Proved reserve life
(years) 41.0 19.0(1) 23.6 n/m n/m
PDP reserve life
(years) 10.2 7.1(1) 10.4 n/m n/m
Excluding
acquisitions
F&D Reserve
additions
(Bcfe) 69.7 120.4 503.2 231.1 242.7 701.4
F&D Costs
incurred $62.9 $133.8 $808.7 $335.1 $388.6 $1,043.0
F&D Costs
per Mcfe $0.90 $1.11 $1.61 $1.45 $1.60 $1.49
Drillbit reserve
replacement 955% 787% 784% 799% 958% 953%
Including
acquisitions
Total reserve
additions
(Bcfe) 158.8 717.1 578.7 484.9 250.9 711.0
Total costs
incurred $98.5 $1,713.6 $1,150.6 $987.6 $567.2 $1,380.5
Reserve
replacement
cost per Mcfe $0.62 $2.39 $1.99 $2.04 $2.26 $1.94
Proved reserve
replacement 2,175% 1,361%(1) 901% 1,171%(1) 990% 966%
(1) Based upon pro forma 2006 production of 52.7 Bcfe
The company's management uses proved reserve replacement as an indicator
of its ability to replenish annual production volumes and grow its reserves.
The company's management believes that reserve replacement is relevant and
useful information that is commonly used by analysts, investors and other
interested parties in the crude oil and natural gas industry as a means of
evaluating the operational performance and prospects of entities engaged in
the production and sale of depleting natural resources. It should be noted
that proved reserve replacement is a statistical indicator that has
limitations. As an annual measure, proved reserve replacement is limited
because it typically varies widely based on the extent and timing of new
discoveries and property acquisitions. Its predictive and comparative value is
also limited for the same reasons. In addition, since proved reserve
replacement does not consider the cost or timing of future production of new
reserves, it cannot be used as a measure of value creation. This financial
measure does not distinguish between changes in reserve quantities that are
developed and those that will require additional time and funding to develop.
Derivative Contracts
The table below sets forth the company's natural gas price and basis swaps
and crude oil swaps and collars for 2008 and 2009 as of November 5, 2008.
Current natural gas and crude oil derivative contracts excluding basis swaps
account for 72% of anticipated production for the fourth quarter of 2008 at
$9.17 per Mcfe and 57% of anticipated production for 2009 at $8.88 per Mcfe.
In addition, the company has 17.35 Bcf of natural gas swaps in 2010 at an
average price of $8.13 per Mcf. The company also has the following natural gas
basis swaps in place: 32.85 Bcf in 2010 at an average price of $0.71 per Mcf
and 5.48 Bcf in 2011 (through December 2011) at an average price of $0.47 per
Mcf.
Quarter Year
Ending Ending
12/31/2008 12/31/2008
Natural Gas Swaps:
Volume (Bcf) 17.48 70.77
Swap $8.67 $8.40
Natural Gas Basis Swaps:
Volume (Bcf) 14.72 55.54
Swap $0.65 $0.60
Crude Oil Hedges:
Swap Volume (MMBbls) 0.23 0.92
Swap $93.17 $94.55
Collar Volume (MMBbls) 0.03 0.10
Collar: High $82.60 $82.93
Collar: Low $50.00 $50.00
Year
Quarter Ending Ending
3/31/2009 6/30/2009 9/30/2009 12/31/2009 12/31/2009
Natural Gas Swaps:
Volume (Bcf) 20.70 17.29 15.03 14.72 67.74
Swap $9.14 $8.27 $8.41 $8.85 $8.69
Natural Gas Basis Swaps:
Volume (Bcf) 16.20 16.38 16.56 16.56 65.70
Swap $0.74 $0.74 $0.74 $0.74 $0.74
Crude Oil Hedges:
Swap Volume (MMBbls) 0.05 0.05 0.05 0.05 0.18
Swap $126.38 $126.71 $126.61 $126.51 $126.55
Collar Volume
(MMBbls) 0.00 0.00 0.00 0.00 0.00
Collar: High n/m n/m n/m n/m n/m
Collar: Low n/m n/m n/m n/m n/m
Since August 5, 2008, the company has entered into the following
additional natural gas and crude oil swaps (also included in the tables above
of derivative contracts as of November 5, 2008):
Quarter Year
Ending Ending
12/31/2008 12/31/2008
Natural Gas Swaps:
Volume (Bcf) 0.00 0.00
Swap n/m n/m
Natural Gas Basis Swaps:
Volume (Bcf) 0.00 0.00
Swap n/m n/m
Crude Oil Hedges:
Swap Volume
(MMBbls) 0.00 0.00
Swap n/m n/m
Collar Volume
(MMBbls) 0.00 0.00
Collar: High n/m n/m
Collar: Low n/m n/m
Year
Quarter Ending Ending
3/31/2009 6/30/2009 9/30/2009 12/31/2009 12/31/2009
Natural Gas Swaps:
Volume (Bcf) 9.90 11.83 11.96 11.96 45.65
Swap $8.01 $7.75 $8.01 $8.48 $8.07
Natural Gas Basis
Swaps:
Volume (Bcf) 12.60 12.74 12.88 12.88 51.10
Swap $0.78 $0.78 $0.78 $0.78 $0.78
Crude Oil Hedges:
Swap Volume
(MMBbls) 0.00 0.00 0.00 0.00 0.00
Swap n/m n/m n/m n/m n/m
Collar Volume
(MMBbls) 0.00 0.00 0.00 0.00 0.00
Collar: High n/m n/m n/m n/m n/m
Collar: Low n/m n/m n/m n/m n/m
Balance Sheet
The company's total debt (short-term and long-term) increased $904.6
million during the first nine months of 2008 primarily as a result of the
issuance of $750.0 million of 8.0% Senior Notes Due 2018 in May 2008. The
company used $478.0 million of the $735.0 million of net proceeds from the
offering to repay borrowings under the company's senior credit facility.
Additionally, during the nine months ended September 30, 2008, the company
made principal payments on its rig loan and mortgage totaling $11.1 million
and $0.6 million, respectively. At September 30, 2008, the company had
classified $16.2 million of its long-term debt as current. This total included
$0.9 million related to the company's mortgage and $15.3 million related to
its rig loan. Total debt as of September 30, 2008 was $1.972 billion compared
to $1.068 billion at year-end 2007. The company was in compliance with all of
its debt covenants at September 30, 2008.
The company's capital structure at December 31, 2007 and September 30,
2008 is presented below:
December 31, September 30,
2007 2008
(in thousands)
Cash and cash equivalents $63,135 $898
Current maturities of long-term debt 15,350 16,227
Long-term debt (net of current
maturities):
Senior credit facility - 166,486
Notes payable - Drilling rig fleet
and oil field services equipment 33,416 21,384
Mortgage 18,829 18,174
Notes payable - Other equipment and
vehicles 54 -
Term loans and Senior Notes:
Senior Floating Rate Term Loan 350,000 -
8.625% Senior Term Loan 650,000 -
Senior Floating Rate Notes due
2014 - 350,000
8.625% Senior Notes due 2015 - 650,000
8.0% Senior Notes due 2018 - 750,000
Total debt 1,067,649 1,972,271
Minority interest 4,672 28
Redeemable convertible preferred stock 450,715 -
Stockholders' equity:
Preferred stock - -
Common stock 140 163
Additional paid-in capital 1,686,113 2,161,891
Treasury stock, at cost (18,578) (19,315)
Retained earnings 99,216 236,362
Total stockholders' equity 1,766,891 2,379,101
Total capitalization $3,289,927 $4,351,400
2008 and 2009 Operational Guidance
Year Ending Year Ending
December 31, 2008 December 31, 2009
Previous Updated Previous Current
Projection Projection Projection Projection
as of as of as of as of
August 7, 2008 November 6, 2008 August 7, 2008 November 6, 2008
Production
Natural
Gas (Bcf) 85.1 85.8 120.0 105.0
Crude
Oil
(MMBbls) 2.5 2.4 2.5 2.5
Total
(Bcfe) 100.0 100.0 135.0 120.0
Differentials
Natural
Gas $0.90 $0.90 $0.90 $0.90
Crude Oil 10.00 10.00 10.00 9.00
Costs per
Mcfe
Lifting $1.56 - $1.72 $1.59 - $1.75 $1.56 - $1.72 $1.59 - $1.75
Production
Taxes 0.44 - 0.49 0.36 - 0.40 0.37 - 0.40 0.27 - 0.30
DD&A -
oil &
gas 2.85 - 3.13 2.85 - 3.13 2.71 - 2.98 2.71 - 2.98
DD&A -
other 0.76 - 0.84 0.75 - 0.82 0.79 - 0.87 0.79 - 0.87
Total
DD&A $3.61 - $3.97 $3.60 - $3.95 $3.50 - $3.85 $3.50 - $3.85
G&A -
cash 0.82 - 0.91 0.85 - 0.94 0.68 - 0.75 0.76 - 0.84
G&A -
stock 0.20 - 0.22 0.20 - 0.22 0.34 - 0.37 0.23 - 0.26
Total
G&A $1.02 - $1.13 $1.05 - $1.16 $1.02 - $1.12 $0.99 - $1.10
Interest
Expense $1.23 - $1.35 $1.27 - $1.40 $1.33 - $1.46 $1.44 - $1.59
Corporate
Tax Rate 36% 36% 36% 36%
Deferral
Rate 95% 95% 95% 95%
Shares
Outstanding
at End of
Period
(in millions)
Common
Stock 165.8 166.1 179.1 167.6
Preferred
Stock
(converted) 0.0 0.0 0.0 0.0
Fully
Diluted 165.8 166.1 179.1 167.6
Capital
Expenditures
($ in
millions)
Exploration
and
Production $1,472 $1,362 $1,600 $750
Land and
Seismic 305 397 125 25
Total
Exploration
and
Production $1,777 $1,759 $1,725 $775
Oil
Field
Services 64 65 75 25
Midstream
and
Other 159 176 200 200
Total
Capital
Expenditures $2,000 $2,000 $2,000 $1,000
The updated 2008 and 2009 operational guidance has not been adjusted to
include the effects of a potential sale of the company's East Texas and North
Louisiana assets and assumes that any 2009 cash flow shortfall will be funded
through debt.
2008 Guidance Update: The company is updating the 2008 production guidance
provided on August 7, 2008 for minor changes in unit costs as shown above. The
remainder of the previously provided guidance is unchanged. Production
guidance remains at 100.0 Bcfe despite shut-in volumes resulting from the Grey
Ranch Plant fire, well work in the Gulf Coast, and the impact of hurricanes in
the Gulf of Mexico.
2009 Guidance Update: On October 2, 2008, the company updated its 2009
production guidance to 120.0 Bcfe from 135.0 Bcfe and capital expenditure
guidance to $1.0 billion from $2.0 billion. The company reaffirms the October
2 guidance. Additionally, the company is updating its operational guidance for
minor changes in unit costs as shown above.
Non-GAAP Financial Measures
The company defines operating cash flow as net cash provided by operating
activities before changes in operating assets and liabilities. It defines
EBITDA as net (loss) income before income tax expense (benefit), interest
expense, and depreciation, depletion and amortization. Adjusted EBITDA, which
is a defined term in the company's credit agreement, is EBITDA excluding
interest income and various non-cash items (including income from equity
investments, minority interest, stock-based compensation, unrealized (gain)
loss on derivative contracts, and provision for doubtful accounts).
Operating cash flow and adjusted EBITDA are supplemental financial
measures used by the company's management and by securities analysts,
investors, lenders, rating agencies and others who follow the industry as an
indicator of the company's ability to internally fund exploration and
development activities and to service or incur additional debt. The company
also uses these measures because operating cash flow and adjusted EBITDA
relate to the timing of cash receipts and disbursements that the company may
not control and may not relate to the period in which the operating activities
occurred. Further, operating cash flow and adjusted EBITDA allow the company
to compare its operating performance and return on capital with those of other
companies without regard to financing methods and capital structure. These
measures should not be considered in isolation or as a substitute for net cash
provided by operating activities prepared in accordance with generally
accepted accounting principles ("GAAP"). Adjusted EBITDA should not be
considered as a substitute for net income, operating income, cash flows from
operating activities or any other measure of financial performance or
liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some,
but not all, items that affect net income and operating income and these
measures may vary among other companies. Therefore, the company's adjusted
EBITDA may not be comparable to similarly titled measures of other companies.
Management also uses the supplemental financial measure of adjusted net
income available (loss applicable) to common stockholders, which excludes
unrealized (losses) gains on derivative contracts from net income available
(loss applicable) to common stockholders. Management uses this financial
measure as an indicator of the company's operational trends and performance
relative to other oil and natural gas companies and believes it is more
comparable to earnings estimates provided by securities analysts. Adjusted
net income available (loss applicable) to common stockholders is not a measure
of financial performance under GAAP and should not be considered a substitute
for net income available (loss applicable) to common stockholders.
The tables below reconcile the most directly comparable GAAP financial
measures to operating cash flow, EBITDA, adjusted EBITDA, and adjusted net
income available (loss applicable) to common stockholders.
Reconciliation of Net Cash Provided by Operating Activities to Operating Cash
Flow
Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
(in thousands) (in thousands)
Net cash provided by operating
activities $237,534 $58,712 $534,368 $239,556
Add (deduct):
Change in operating assets and
liabilities (100,348) 14,614 (108,735) (53,133)
Operating cash flow $137,186 $73,326 $425,633 $186,423
Reconciliation of Net Income to EBITDA and Adjusted EBITDA
Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
(in thousands) (in thousands)
Net income(1) $230,346 $20,920 $153,378 $35,991
Adjusted for:
Income tax expense 130,693 11,920 89,308 21,002
Interest expense(2) 38,326 28,522 96,170 88,630
Depreciation, depletion and
amortization - other 17,597 14,282 51,342 36,545
Depreciation, depletion and
amortization - natural
gas and crude oil 71,964 45,177 209,296 115,876
EBITDA 488,926 120,821 599,494 298,044
Provision for doubtful accounts 1,623 - 1,623 -
Income from equity investments 60 (1,235) (1,355) (3,399)
Minority interest 2 164 853 321
Interest income (923) (544) (3,068) (3,671)
Stock-based compensation 7,023 2,704 14,283 4,962
Unrealized gains on derivative
contracts (317,092) (19,279) (81,603) (36,052)
Adjusted EBITDA $179,619 $102,631 $530,227 $260,205
(1) Includes gain on sale of assets
(2) Excludes unrealized loss (gain) of $2.7 million and ($7.7) million on
interest rate swap for the three and nine month periods ended
September 30, 2008, respectively.
Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA
Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
(in thousands) (in thousands)
Net cash provided by operating
activities $237,534 $58,712 $534,368 $239,556
Changes in operating assets and
liabilities (100,348) 14,614 (108,735) (53,133)
Interest expense(1) 38,326 28,522 96,170 88,630
Unrealized gains on derivative
contracts 317,092 19,279 81,603 36,052
Gain on sale of assets 1,420 1,045 9,131 1,704
Other non-cash items (314,405) (19,541) (82,310) (52,604)
Adjusted EBITDA $179,619 $102,631 $530,227 $260,205
(1) Excludes unrealized loss (gain) of $2.7 million and ($7.7) million on
interest rate swap for the three and nine month periods ended
September 30, 2008, respectively.
Reconciliation of Net Income Available (Loss Applicable) to Common
Stockholders to Adjusted Net Income Available (Loss Applicable) to Common
Stockholders
Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
(in thousands) (in thousands)
Net income available (loss
applicable) to
common stockholders $230,346 $11,607 $137,146 $5,418
Unrealized gains on derivative
contracts (317,092) (19,278) (81,603) (36,052)
Effect of income taxes 114,785 6,997 30,030 13,285
Adjusted net income available
(loss applicable) to
common stockholders $28,039 $(674) $85,573 $(17,349)
Per share:
Basic $0.17 $(0.01) $0.56 $(0.17)
Diluted $0.17 $(0.01) $0.55 $(0.17)
Conference Call Information
The company will host a conference call to discuss these results on
Friday, November 7, 2008 at 9:00 am EST. The telephone number to access the
conference call from within the U.S. is 866-356-4279 and from outside the U.S.
is 617-597-5394. The passcode for the call is 78732749. An audio replay of the
call will be available at noon EST on November 7, 2008 until 12:59 am EST on
November 21, 2008. The number to access the conference call replay from within
the U.S. is 888-286-8010 and from outside the U.S. is 617-801-6888. The
passcode for the replay is 18245385.
A live audio webcast of the conference call also will be available via
SandRidge's website, http://www.sandridgeenergy.com, under Investor
Relations/Events. A brief slide presentation to be viewed in conjunction with
this conference call is currently available at the same location on the
website. The webcast will be archived for replay on the company's website for
30 days.
Future 2008 Earnings Releases, Conference Calls and 2009 Investor/Analyst
Conference Information
Fourth Quarter and Year End 2008 Earnings and Conference Call:
February 26, 2009 (Thursday) - Earnings press release and filing of
Form 10-K after market close
February 27, 2009 (Friday) - Earnings conference call at 9:00 am EST
2009 Investor/Analyst Conference:
March 3, 2009 (Tuesday) - New York, NY at the Grand Hyatt, 109 East
42nd Street at 8:00 am EST
SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations
Three Months Ended Nine Months Ended
September 30, September 30,
2008 2007 2008 2007
(Unaudited)
(In thousands, except per share amounts)
Revenues:
Natural gas and crude oil $259,141 $113,106 $756,762 $319,556
Drilling and services 12,054 16,684 36,345 56,928
Midstream and marketing 58,343 19,030 174,240 71,131
Other 4,485 4,828 13,812 14,160
Total revenues 334,023 153,648 981,159 461,775
Expenses:
Production 41,070 28,689 115,512 77,707
Production taxes 6,717 4,402 29,456 12,328
Drilling and services 8,191 6,809 20,426 30,935
Midstream and marketing 51,908 14,444 157,059 61,191
Depreciation, depletion and
amortization - natural gas
and crude oil 71,964 45,177 209,296 115,876
Depreciation, depletion and
amortization - other 17,597 14,282 51,342 36,545
General and administrative 29,235 20,421 76,432 45,781
(Gain) loss on derivative
contracts (292,526) (39,247) 4,086 (55,228)
Gain on sale of assets (1,420) (1,045) (9,131) (1,704)
Total expenses (67,264) 93,932 654,478 323,431
Income from operations 401,287 59,716 326,681 138,344
Other income (expense):
Interest income 923 544 3,068 3,671
Interest expense (41,026) (28,522) (88,421) (88,630)
Minority interest (2) (164) (853) (321)
(Loss) income from equity
investments (60) 1,235 1,355 3,399
Other (expense) income, net (83) 31 856 530
Total other (expense) income (40,248) (26,876) (83,995) (81,351)
Income before income tax expense 361,039 32,840 242,686 56,993
Income tax expense 130,693 11,920 89,308 21,002
Net income 230,346 20,920 153,378 35,991
Preferred stock dividends and
accretion - 9,313 16,232 30,573
Income available to common
stockholders $230,346 $11,607 $137,146 $5,418
Income per share available to
common stockholders:
Basic $1.41 $0.11 $0.90 $0.05
Diluted $1.40 $0.11 $0.89 $0.05
Weighted average number of common
shares outstanding:
Basic 163,020 107,554 153,125 102,562
Diluted 164,554 109,049 154,489 103,778
SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
September 30, December 31,
2008 2007
(Unaudited)
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $898 $63,135
Accounts receivable, net:
Trade 99,062 94,741
Related parties 13,874 20,018
Derivative contracts 87,751 21,958
Inventories 7,318 3,993
Deferred income taxes 3,528 1,820
Other current assets 29,858 20,787
Total current assets 242,289 226,452
Natural gas and crude oil properties,
using full cost method of accounting
Proved 4,155,044 2,848,531
Unproved 211,314 259,610
Less: accumulated depreciation and
depletion (434,561) (230,974)
3,931,797 2,877,167
Other property, plant and equipment,
net 612,428 460,243
Derivative contracts 16,080 270
Investments 9,311 7,956
Restricted deposits 32,745 31,660
Other assets 45,852 26,818
Total assets $4,890,502 $3,630,566
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt $16,227 $15,350
Accounts payable and accrued
expenses:
Trade 314,444 215,497
Related parties 575 395
Asset retirement obligation 1,524 864
Billings in excess of costs incurred 11,885 -
Total current liabilities 344,655 232,106
Long-term debt 1,956,044 1,052,299
Other long-term obligations 11,817 16,817
Asset retirement obligation 64,574 57,716
Deferred income taxes 134,283 49,350
Total liabilities 2,511,373 1,408,288
Commitments and contingencies
Minority interest 28 4,672
Redeemable convertible preferred
stock, $0.001 par value, 2,625
shares authorized; 0 and 2,184 shares
issued and outstanding at
September 30, 2008 and December 31, 2007,
respectively - 450,715
Stockholders' equity:
Preferred stock, $0.001 par value;
47,375 shares authorized; no shares
issued and outstanding in 2008 and 2007 - -
Common stock, $0.001 par value;
400,000 shares authorized;
166,973 issued and 165,648
outstanding at September 30, 2008
and 141,847 issued and 140,391
outstanding at December 31, 2007 163 140
Additional paid-in capital 2,161,891 1,686,113
Treasury stock, at cost (19,315) (18,578)
Retained earnings 236,362 99,216
Total stockholders' equity 2,379,101 1,766,891
Total liability and
stockholders' equity $4,890,502 $3,630,566
SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows
Nine Months Ended
September 30,
2008 2007
(Unaudited)
(In thousands)
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $153,378 $35,991
Adjustments to reconcile net income
to net cash provided by operating
activities:
Provision for doubtful accounts 1,623 -
Depreciation, depletion and
amortization 260,638 152,421
Debt issuance cost amortization 4,026 14,903
Deferred income taxes 83,225 20,004
Unrealized gain on derivative
contracts (81,603) (36,052)
Gain on sale of assets (9,131) (1,704)
Interest income - restricted
deposits (304) (1,024)
Income from equity investments (1,355) (3,399)
Stock-based compensation, net of tax 14,283 4,962
Minority interest 853 321
Changes in operating assets and
liabilities 108,735 53,133
Net cash provided by operating
activities 534,368 239,556
CASH FLOWS FROM INVESTING
ACTIVITIES:
Capital expenditures for
property, plant and equipment (1,609,355) (895,160)
Acquisition of assets - (3,001)
Proceeds from sale of assets 158,534 6,458
Loans to unconsolidated investees (5,500) -
Fundings of restricted deposits (781) (5,638)
Net cash used in investing
activities (1,457,102) (897,341)
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from borrowings 1,768,722 1,262,769
Repayments of borrowings (864,100) (879,592)
Dividends paid - preferred (17,552) (24,366)
Minority interest (distributions)
contributions (5,497) 192
Proceeds from issuance of common
stock - 319,966
Purchase of treasury stock (3,536) (1,579)
Debt issuance costs (17,540) (26,540)
Net cash provided by financing
activities 860,497 650,850
NET DECREASE IN CASH AND CASH
EQUIVALENTS (62,237) (6,935)
CASH AND CASH EQUIVALENTS, beginning
of year 63,135 38,948
CASH AND CASH EQUIVALENTS, end of period $898 $32,013
Supplemental Disclosure of Noncash
Investing and Financing Activities:
Insurance premiums financed $- $1,496
Accretion on redeemable convertible
preferred stock $7,636 $1,062
Redeemable convertible preferred
stock dividends, net of dividends
paid $- $8,956
Property, plant and equipment
addition due to settlement $- $4,500
For further information, please contact:
Dirk M. Van Doren
Chief Financial Officer
SandRidge Energy, Inc.
123 Robert S. Kerr Avenue
Oklahoma City, OK 73102-6406
(405) 429-5520
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. 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 future natural gas and crude
oil production, pricing differentials, operating costs and capital spending,
descriptions of our development plans and provide internal estimates of proved
reserves and future net cash flows. 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
natural gas and oil prices, our success in discovering, estimating, developing
and replacing natural gas and oil reserves, the availability and terms of
capital, the ability of counterparties to our financial transactions to meet
their obligations, our timely execution of hedge transactions, credit
conditions of global capital markets, the risk of a recession, the receipt of
adequate proceeds for our East Texas and North Louisiana properties, 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 other factors, many of which are beyond our control. We
refer you to the discussion of risk factors in the prospectus we filed with
the Securities and Exchange Commission ("SEC") on September 17, 2008 and in
Part II, Item 1A - Risk Factors of our Quarterly Report on Form 10-Q filed
with the SEC today. 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.
Cautionary Note to Investors - The United States SEC permits oil and gas
companies, in their filings with the SEC, to disclose only proved reserves
that a company has demonstrated by actual production or conclusive formation
tests to be economically and legally producible under existing economic and
operating conditions. We use certain terms in the press release, such as
"probable reserves" and "possible reserves," that the SEC's guidelines
strictly prohibit us from including in filings with the SEC. Investors are
urged to consider closely the disclosures in our 2007 Form 10-K, File No. 001-
33784, available from us at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma
73102 or http://www.sandridgeenergy.com. You may also access our filings with
the SEC at http://www.sec.gov or obtain copies from the SEC by calling 1-800-
732-0330.
SandRidge Energy, Inc. is a natural gas and crude oil company
headquartered in Oklahoma City, Oklahoma with its principal focus on
exploration and production. SandRidge also owns and operates gas gathering and
processing facilities and CO2 treating and transportation facilities, and has
marketing and tertiary oil recovery operations. In addition, SandRidge owns
and operates drilling rigs and a related oil field services business operating
under the Lariat Services, Inc. brand name. SandRidge focuses its exploration
and production activities in West Texas, the Cotton Valley Trend in East
Texas, the Gulf Coast, the Mid-Continent, and the Gulf of Mexico. SandRidge's
Internet address is http://www.sandridgeenergy.com.
SOURCE SandRidge Energy, Inc.
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