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Company Reports 2008 First Quarter Production of 2.2 Bcfe per Day; Increase of 31% Over 2007 First Quarter Production
2008 First Quarter Net Loss to Common Shareholders of $143
Million, or $0.29 per Fully Diluted Common Share Reported; Adjusted
Net Income Available to Common Shareholders Increases 32% Over 2007
First Quarter to $561 Million, or $1.09 per Fully Diluted Common
Share, a Company Record
Proved Reserves Reach Record Level of 11.5 Tcfe and Increase 6%
Year-to-Date; Company Delivers First Quarter Reserve Replacement Rate
of 395% from 601 Bcfe of Net Additions at a Drilling and Net
Acquisition Cost of $1.95 per Mcfe
Chesapeake Agrees to Sell 94 Bcfe of Proved Reserves for Proceeds
of $623 Million, or $6.63 per Mcfe, in a Volumetric Production Payment
Transaction; Company Announces Plans to Sell Remaining Arkoma Basin
Woodford Shale Properties for Anticipated Proceeds of Over $1.5
Billion
OKLAHOMA CITY--(BUSINESS WIRE)--May 1, 2008--In BW6354 issued May
1, 2008: Reissuing release to replace operational results table for
the Fayetteville Shale play.
The corrected release reads:
CHESAPEAKE ENERGY CORPORATION REPORTS FINANCIAL AND OPERATIONAL
RESULTS FOR THE 2008 FIRST QUARTER
Company Reports 2008 First Quarter Production of 2.2 Bcfe per Day;
Increase of 31% Over 2007 First Quarter Production
2008 First Quarter Net Loss to Common Shareholders of $143
Million, or $0.29 per Fully Diluted Common Share Reported; Adjusted
Net Income Available to Common Shareholders Increases 32% Over 2007
First Quarter to $561 Million, or $1.09 per Fully Diluted Common
Share, a Company Record
Proved Reserves Reach Record Level of 11.5 Tcfe and Increase 6%
Year-to-Date; Company Delivers First Quarter Reserve Replacement Rate
of 395% from 601 Bcfe of Net Additions at a Drilling and Net
Acquisition Cost of $1.95 per Mcfe
Chesapeake Agrees to Sell 94 Bcfe of Proved Reserves for Proceeds
of $623 Million, or $6.63 per Mcfe, in a Volumetric Production Payment
Transaction; Company Announces Plans to Sell Remaining Arkoma Basin
Woodford Shale Properties for Anticipated Proceeds of Over $1.5
Billion
Chesapeake Energy Corporation (NYSE:CHK) today announced financial
and operating results for the 2008 first quarter. Due to an unrealized
non-cash after-tax mark-to-market loss of $704 million from future
period natural gas and oil and interest rate hedges primarily as a
result of higher natural gas and oil prices as of March 31, 2008
compared to December 31, 2007, Chesapeake reported a net loss to
common shareholders during the quarter of $143 million ($0.29 per
fully diluted common share), operating cash flow of $1.512 billion
(defined as cash flow from operating activities before changes in
assets and liabilities) and ebitda of $438 million (defined as net
income (loss) before income taxes, interest expense, and depreciation,
depletion and amortization expense) on revenue of $1.611 billion and
production of 204 billion cubic feet of natural gas equivalent (bcfe).
The company's $704 million loss referenced above was offset by
$132 million in realized after-tax cash gains from hedging activities
for actual volumes produced during the quarter. Further, this
unrealized loss is an item that is typically not included in published
estimates of the company's financial results by certain securities
analysts. Excluding this item, Chesapeake's adjusted net income to
common shareholders in the 2008 first quarter was $561 million ($1.09
per fully diluted common share) and adjusted ebitda was $1.570
billion, increases of 32% and 27%, respectively, over the 2007 first
quarter. This adjusted net income to common shareholders for the
quarter of $1.09 per share is the highest achieved in the company's
history. The excluded item does not affect the calculation of
operating cash flow. A reconciliation of operating cash flow, ebitda,
adjusted ebitda and adjusted net income to comparable financial
measures calculated in accordance with generally accepted accounting
principles is presented on pages 17 - 18 of this release.
Key Operational and Financial Statistics Summarized
The table below summarizes Chesapeake's key results during the
2008 first quarter and compares them to results during the 2007 fourth
quarter and the 2007 first quarter. The 2008 first quarter results
reflect the sale of 55 million cubic feet of natural gas equivalent
(mmcfe) per day of production in a volumetric production payment (VPP)
transaction as of December 31, 2007.
Three Months Ended:
--------------------------------
3/31/08 12/31/07 3/31/07
--------- ---------- ---------
Average daily production (in mmcfe) 2,244 2,219 1,707
Natural gas as % of total production 92 92 92
Natural gas production (in bcf) 187.8 187.8 140.8
Average realized natural gas price
($/mcf) (a) 9.05 8.11 9.26
Oil production (in mbbls) 2,746 2,735 2,143
Average realized oil price ($/bbl)
(a) 74.73 72.58 61.13
Natural gas equivalent production (in
bcfe) 204.2 204.2 153.7
Natural gas equivalent realized price
($/mcfe) (a) 9.33 8.43 9.33
Natural gas and oil marketing income
($/mcfe) .11 .09 .10
Service operations income ($/mcfe) .03 .04 .08
Production expenses ($/mcfe) (.98) (.88) (.93)
Production taxes ($/mcfe) (.37) (.32) (.27)
General and administrative costs
($/mcfe) (b) (.29) (.29) (.27)
Stock-based compensation ($/mcfe) (.09) (.08) (.07)
DD&A of natural gas and oil
properties ($/mcfe) (2.52) (2.55) (2.56)
D&A of other assets ($/mcfe) (.18) (.16) (.23)
Interest expense ($/mcfe) (a) (.43) (.49) (.50)
Operating cash flow ($ in millions)
(c) 1,512 1,322 1,124
Operating cash flow ($/mcfe) 7.40 6.48 7.31
Adjusted ebitda ($ in millions) (d) 1,570 1,432 1,234
Adjusted ebitda ($/mcfe) 7.69 7.01 8.03
Net income (loss) to common
shareholders ($ in millions) (143) 158 232
Earnings (loss) per share - assuming
dilution ($) (.29) .33 .50
Adjusted net income to common
shareholders
($ in millions) (e) 561 466 425
Adjusted earnings per share -
assuming dilution ($) 1.09 .93 .87
(a) includes the effects of realized gains or (losses) from
hedging, but does not include the effects of unrealized gains or
(losses) from hedging
(b) excludes expenses associated with non-cash stock-based
compensation
(c) defined as cash flow provided by operating activities before
changes in assets and liabilities
(d) defined as net income (loss) before income taxes, interest
expense, and depreciation, depletion and amortization expense, as
adjusted to remove the effects of certain items detailed on page 18
(e) defined as net income (loss) available to common shareholders,
as adjusted to remove the effects of certain items detailed on page 18
Natural Gas and Oil Production Sets Record for 27th Consecutive
Quarter; 2008 First Quarter Average Daily Production Increases 31%
over 2007 First Quarter Production
Daily production for the 2008 first quarter averaged 2.244 bcfe,
an increase of 25 mmcfe, or 1%, over the 2.219 bcfe produced per day
in the 2007 fourth quarter and an increase of 537 mmcfe, or 31%, over
the 1.707 bcfe produced per day in the 2007 first quarter. Adjusted
for the company's year-end 2007 VPP sale, Chesapeake's sequential and
year-over-year production growth rates were 4% and 35%, respectively.
Chesapeake's average daily production for the 2008 first quarter
consisted of 2.063 billion cubic feet of natural gas (bcf) and 30,176
barrels of oil and natural gas liquids (bbls). The company's 2008
first quarter production of 204.2 bcfe was comprised of 187.8 bcf (92%
on a natural gas equivalent basis) and 2.75 million barrels of oil and
natural gas liquids (mmbbls) (8% on a natural gas equivalent basis).
The 2008 first quarter was Chesapeake's 27th consecutive quarter
of sequential U.S. production growth. Over these 27 quarters,
Chesapeake's U.S. production has increased 467%, for an average
compound quarterly growth rate of 6.6% and an average compound annual
growth rate of 29.2%.
Natural Gas and Oil Proved Reserves Reach Record Level of 11.5
Tcfe; Company Adds 601 Bcfe of Net Proved Reserves for a Reserve
Replacement Rate of 395% at an Average Drilling and Net Acquisition
Cost of $1.95 per Mcfe
Chesapeake began 2008 with estimated proved reserves of 10.879
trillion cubic feet of natural gas equivalent (tcfe) and ended the
first quarter with 11.480 tcfe, an increase of 601 bcfe, or 6%. During
the quarter, Chesapeake replaced its 204 bcfe of production with an
estimated 805 bcfe of new proved reserves for a reserve replacement
rate of 395%. Reserve replacement through the drillbit was 798 bcfe,
or 391% of production. This includes 365 bcfe of positive performance
revisions (including 342 bcfe related to infill drilling and increased
density locations) and 112 bcfe of positive revisions resulting from
natural gas and oil price increases between December 31, 2007 and
March 31, 2008. Acquisitions of proved reserves completed during the
quarter were 39 bcfe at a cost of $63 million, or $1.59 per mcfe,
while sales of proved reserves during the quarter totaled 32 bcfe for
proceeds of $86 million, or $2.72 per mcfe. Sales of undeveloped
leasehold during the quarter generated proceeds of $159 million.
Chesapeake's total drilling and net acquisition costs for the
quarter were $1.95 per mcfe. This calculation excludes costs of $694
million for the acquisition of unproved properties and leasehold (net
of sales), $80 million for capitalized interest on leasehold and
unproved properties, $84 million for seismic, and $16 million relating
to tax basis step-up and asset retirement obligations, as well as
positive revisions of proved reserves from higher natural gas and oil
prices. Excluding these items and acquisition and divestiture activity
of proved properties, during the quarter Chesapeake's exploration and
development costs through the drillbit were $2.00 per mcfe. A complete
reconciliation of finding and acquisition costs and a roll-forward of
proved reserves are presented on page 15 of this release.
During the 2008 first quarter, Chesapeake continued the industry's
most active drilling program and drilled 478 gross (400 net) operated
wells and participated in another 422 gross (48 net) wells operated by
other companies. The company's drilling success rate was 100% for
company-operated wells and 98% for non-operated wells. Also during the
quarter, Chesapeake invested $1.182 billion in operated wells (using
an average of 140 operated rigs) and $192 million in non-operated
wells (using an average of 93 non-operated rigs).
As of March 31, 2008, Chesapeake's estimated future net cash flows
from proved reserves, discounted at an annual rate of 10% before
income taxes (PV-10), were $32.4 billion using field differential
adjusted prices of $8.54 per thousand cubic feet of natural gas (mcf)
(based on a NYMEX quarter-end price of $9.37 per mcf) and $96.37 per
bbl (based on a NYMEX quarter-end price of $101.60 per bbl). By
comparison, Chesapeake's enterprise value (market equity value plus
long-term debt less working capital) as of March 31 was approximately
$39.5 billion. Chesapeake's PV-10 changes by approximately $400
million for every $0.10 per mcf change in natural gas prices and
approximately $60 million for every $1.00 per bbl change in oil
prices.
By comparison, the December 31, 2007 PV-10 of the company's proved
reserves was $20.6 billion ($15 billion applying the SFAS 69
standardized measure) using field differential adjusted prices of
$6.19 per mcf (based on a NYMEX year-end price of $6.80 per mcf) and
$90.58 per bbl (based on a NYMEX year-end price of $96.00 per bbl).
The March 31, 2007 PV-10 of the company's proved reserves was $20.2
billion using field differential adjusted prices of $7.01 per mcf
(based on a NYMEX quarter-end price of $7.34 per mcf) and $60.75 per
bbl (based on a NYMEX quarter-end price of $65.85 per bbl).
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.
In addition to the PV-10 value of its proved reserves, Chesapeake
believes the market value of its undeveloped leasehold in just four
shale plays - the Fort Worth Barnett, Fayetteville, Haynesville and
Marcellus - is approximately $25 billion. Also, the net book value of
the company's non-E&P assets (including gathering systems,
compressors, land and buildings, investments, long-term derivative
instruments and other non-current assets) was $3.6 billion as of March
31, 2008, $3.2 billion as of December 31, 2007 and $2.7 billion as of
March 31, 2007.
Average Realized Prices, Hedging Results and Hedging Positions
Detailed
Average prices realized during the 2008 first quarter (including
realized gains or losses from natural gas and oil derivatives, but
excluding unrealized gains or losses on such derivatives) were $9.05
per mcf and $74.73 per bbl, for a realized natural gas equivalent
price of $9.33 per mcfe. Realized gains and losses from natural gas
and oil hedging activities during the 2008 first quarter generated a
$1.42 gain per mcf and a $19.41 loss per bbl for a 2008 first quarter
realized hedging gain of $214 million, or $1.05 per mcfe. Excluding
hedging activity, Chesapeake's average realized pricing basis
differentials to NYMEX during the 2008 first quarter were a negative
$0.40 per mcf and a negative $3.76 per bbl.
By comparison, average prices realized during the 2007 first
quarter (including realized gains or losses from natural gas and oil
derivatives, but excluding unrealized gains or losses on such
derivatives) were $9.26 per mcf and $61.13 per bbl, for a realized
natural gas equivalent price of $9.33 per mcfe. Realized gains from
natural gas and oil hedging activities during the 2007 first quarter
generated a $2.95 gain per mcf and an $8.33 gain per bbl for a 2007
first quarter realized hedging gain of $433 million, or $2.82 per
mcfe. Excluding hedging activity, Chesapeake's average realized
pricing basis differentials to NYMEX during the 2007 first quarter
were a negative $0.46 per mcf and a negative $5.36 per bbl.
The following tables compare Chesapeake's open hedge position
through swaps and collars as well as gains from lifted hedges as of
May 1, 2008 to those previously announced as of March 31, 2008.
Depending on changes in natural gas and oil futures markets and
management's view of underlying natural gas and oil supply and demand
trends, Chesapeake may either increase or decrease its hedging
positions at any time in the future without notice.
Open Swap Positions as of May 1, 2008
Natural Gas Oil
-------------------- --------------------
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
========================== ========== ========= ========== =========
2008 Q2 78% 8.58 70% 75.58
2008 Q3 79% 8.87 75% 76.92
2008 Q4 71% 9.42 67% 79.01
========================== ========== ========= ========== =========
2008 Q2-Q4 Total 76% 8.96 71% 77.16
========================== ========== ========= ========== =========
2009 Total 52% 9.37 70% 82.33
========================== ========== ========= ========== =========
2010 Total 20% 9.56 37% 90.25
========================== ========== ========= ========== =========
Open Natural Gas Collar Positions as of May 1, 2008
Average Average
Floor Ceiling
Quarter or Year % Hedged $ NYMEX $ NYMEX
================================== ========== ========= =========
2008 Q2 6% 8.27 9.92
2008 Q3 5% 8.27 9.92
2008 Q4 4% 8.20 9.91
================================== ========== ========= =========
2008 Q2-Q4 Total 5% 8.25 9.92
================================== ========== ========= =========
2009 Total 5% 8.14 10.82
================================== ========== ========= =========
Gains from Lifted Natural Gas Hedges as of May 1, 2008
Assuming
Natural Gas
Total Gain Production of: Gain
Quarter or Year ($ millions) (bcf) ($ per mcf)
==================== ============== ================ =============
2008 Q2 40 191 0.21
2008 Q3 39 203 0.19
2008 Q4 50 214 0.23
==================== ============== ================ =============
2008 Q2-Q4 Total 129 608 0.21
==================== ============== ================ =============
2009 Total 33 928 0.04
==================== ============== ================ =============
Open Swap Positions as of March 31, 2008
Natural Gas Oil
------------------- --------------------
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
=========================== ========= ========= ========== =========
2008 Q1 76% 8.64 68% 73.97
2008 Q2 75% 8.54 71% 75.58
2008 Q3 71% 8.71 76% 76.92
2008 Q4 64% 9.23 70% 79.01
=========================== ========= ========= ========== =========
2008 Total 71% 8.77 71% 76.40
=========================== ========= ========= ========== =========
2009 Total 40% 9.13 76% 82.33
=========================== ========= ========= ========== =========
Open Natural Gas Collar Positions as of March 31, 2008
Average Average
Floor Ceiling
Quarter or Year % Hedged $ NYMEX $ NYMEX
=================================== ========== ========= =========
2008 Q1 10% 7.36 9.28
2008 Q2 5% 8.27 9.91
2008 Q3 4% 8.27 9.91
2008 Q4 3% 8.19 9.88
=================================== ========== ========= =========
2008 Total 6% 7.88 9.64
=================================== ========== ========= =========
2009 Total 6% 8.22 10.70
=================================== ========== ========= =========
Gains from Lifted Natural Gas Hedges as of March 31, 2008
Assuming
Natural Gas
Total Gain Production of: Gain
Quarter or Year ($ millions) (bcf) ($ per mcf)
==================== ============== ================ =============
2008 Q1 156 184 0.85
2008 Q2 41 195 0.21
2008 Q3 38 208 0.18
2008 Q4 47 216 0.22
==================== ============== ================ =============
2008 Total 282 803 0.35
==================== ============== ================ =============
2009 Total 22 934 0.02
==================== ============== ================ =============
Certain open natural gas swap positions include knockout swaps
with knockout provisions at prices ranging from $5.45 to $6.50 per mcf
covering 187 bcf in 2008, $5.45 to $7.25 per mcf covering 332 bcf in
2009 and $5.45 to $7.25 per mcf covering 172 bcf in 2010. Certain open
natural gas collar positions include three-way collars that include
written put options with strike prices ranging from $5.50 to $6.00 per
mcf covering 46 bcf in 2009 and at $6.00 per mcf covering 3.7 bcf in
2010. Also, certain open oil swap positions include cap-swaps and
knockout swaps with provisions limiting the counterparty's exposure
below prices ranging from $45 to $65 per bbl covering 3.4 mmbbls in
2008, from $53 to $60 per bbl covering 7.8 mmbbls in 2009 and $60 per
bbl covering 4.7 mmbbls in 2010.
The company's updated forecasts for 2008 through 2010 are attached
to this release in an Outlook dated May 1, 2008, labeled as Schedule
"A," which begins on page 19. This Outlook has been changed from the
Outlook dated March 31, 2008 (attached as Schedule "B," which begins
on page 23) to reflect various updated information and include our
first forecast for 2010.
Chesapeake's Leasehold and 3-D Seismic Inventories Increase to
13.9 Million Net Acres and 20 Million Acres; Risked Unproved Reserves
in the Company's Inventory Reach 37 Tcfe While Unrisked Unproved
Reserves Reach 115 Tcfe
Since 2000, Chesapeake has invested $10.3 billion in new leasehold
and 3-D seismic acquisitions and now owns the largest combined
inventories of onshore leasehold (13.9 million net acres) and 3-D
seismic (20.0 million acres) in the U.S. On this leasehold, Chesapeake
has an estimated 4.0 tcfe of proved undeveloped reserves and
approximately 37.2 tcfe of risked unproved reserves (115.5 tcfe of
unrisked unproved reserves). The company is currently using 145
operated drilling rigs to further develop its inventory of
approximately 33,700 net drillsites, representing more than a 10-year
inventory of drilling projects.
Chesapeake categorizes its drilling inventory into two play types:
conventional gas resource and unconventional gas resource. In these
plays, Chesapeake uses a probability-weighted statistical approach to
estimate the potential number of drillsites and unproved reserves
associated with such drillsites. The following table summarizes
Chesapeake's ownership and activity in each gas resource play type and
the following narrative highlights notable projects in the company's
drilling inventory.
----------------------------------------------------------------------
Est.
Est. Risked Avg. Total
CHK Drilling Net Reserves Proved
Net Density Undrilled Per Well Reserves
Play Area Acreage (Acres) Wells (bcfe) (bcfe)
----------------------------------------------------------------------
Conventional Gas
Resource
----------------------
Southern Oklahoma 330,000 120 600 2.20 772
South Texas 150,000 80 425 2.00 408
Mountain Front 140,000 320 100 5.00 218
Other Conventional 3,580,000 Various 3,975 Various 2,498
----------------------------------------------------------------------
Conventional Sub-total 4,200,000 5,100 3,896
Unconventional Gas
Resource
----------------------
Fayetteville Shale
(Core Area) 585,000 80 5,400 2.20 429
Fort Worth Barnett
Shale 260,000 50 3,500 2.50 2,335
Sahara 885,000 70 7,700 0.55 1,100
Colony, Granite &
Atoka Washes 310,000 120 1,000 3.25 1,007
Marcellus Shale 1,200,000 160 1,350 2.00 ND
Deep Haley 560,000 320 335 6.00 283
Haynesville Shale 300,000 ND ND ND ND
Other Unconventional 5,600,000 Various 9,315 Various 2,430
----------------------------------------------------------------------
Unconventional Sub-
total 9,700,000 28,600 7,584
----------------------------------------------------------------------
Total 13,900,000 33,700 11,480
----------------------------------------------------------------------
----------------------------------------------------------------------
Total
Proved
and
Risked Risked Unrisked Current Current
Unproved Unproved Unproved Daily Operated
Reserves Reserves Reserves Production Rig
Play Area (bcfe) (bcfe) (bcfe) (mmcfe) Count
----------------------------------------------------------------------
Conventional Gas
Resource
-----------------------
Southern Oklahoma 800 1,572 3,100 205 7
South Texas 500 908 2,000 115 6
Mountain Front 300 518 1,100 85 2
Other Conventional 3,200 5,698 17,300 555 15
----------------------------------------------------------------------
Conventional Sub-total 4,800 8,696 23,500 960 30
Unconventional Gas
Resource
-----------------------
Fayetteville Shale
(Core Area) 9,600 10,029 13,000 130 14
Fort Worth Barnett
Shale 5,900 8,235 7,200 430 41
Sahara 3,000 4,100 4,100 190 11
Colony, Granite & Atoka
Washes 2,100 3,107 4,000 175 12
Marcellus Shale 1,900 ND 12,800 ND 3
Deep Haley 1,400 1,683 7,400 100 5
Haynesville Shale ND ND ND ND 4
Other Unconventional 8,500 10,930 43,500 275 25
----------------------------------------------------------------------
Unconventional Sub-
total 32,400 39,984 92,000 1,300 115
----------------------------------------------------------------------
Total 37,200 48,680 115,500 2,260 145
----------------------------------------------------------------------
ND = Not disclosed
Fort Worth Barnett Shale (North Texas): The Fort Worth Barnett
Shale is the largest and most prolific unconventional gas resource
play in the U.S. In this play, Chesapeake is the second-largest
producer of natural gas, the most active driller and the largest
leasehold owner in the Core and Tier 1 sweet spots of Tarrant, Johnson
and western Dallas counties. During the 2008 first quarter,
Chesapeake's average daily net production of 410 mmcfe in the play
increased approximately 125% over the 2007 first quarter and 12% over
the 2007 fourth quarter. Chesapeake is currently producing
approximately 430 mmcfe net per day from the play and anticipates
reaching 650 mmcfe net per day by year-end 2008.
The company's proved reserves of 2.3 tcfe in the Fort Worth
Barnett Shale play at the end of the 2008 first quarter increased 78%
over the 2007 first quarter and 13% over year-end 2007. Chesapeake is
currently using 41 operated rigs to further develop its 260,000 net
acres of leasehold, of which 225,000 net acres are located in the
prime Core and Tier 1 areas. Assuming an additional 3,500 net wells
are drilled in the years ahead, the company's estimated risked
unproved reserves in the play are 5.9 tcfe (7.2 tcfe of unrisked
unproved reserves). The table below highlights operational results
over the past five quarters from Chesapeake's operated wells in the
Fort Worth Barnett Shale play.
----------------------------------------------------------------------
Number of Wells Average Average
Placed on Peak Rate (1) Lateral Length
Quarter Production (mcfe/d) (feet)
----------------------------------------------------------------------
2007 Q1 55 2,594 2,373
2007 Q2 80 3,023 2,594
2007 Q3 106 3,464 2,576
2007 Q4 148 3,462 2,834
2008 Q1 107 3,371 2,897
----------------------------------------------------------------------
Total / Weighted Average 496 3,183 2,655
----------------------------------------------------------------------
(1) Peak rate defined as the highest production rate of a well
over a 24-hour period
Fayetteville Shale (Arkansas): In the Fayetteville Shale,
Chesapeake is the second-largest leasehold owner in the Core area of
the play. During the 2008 first quarter, Chesapeake's average daily
net production of 114 mmcfe in the play increased approximately 700%
over the 2007 first quarter and 50% over the 2007 fourth quarter.
Chesapeake is currently producing approximately 130 mmcfe net per day
from the play and anticipates reaching 200 mmcfe net per day by
year-end 2008.
The company's proved reserves of 429 bcfe in the Fayetteville
Shale play at the end of the 2008 first quarter increased 380% over
the 2007 first quarter and 28% over year-end 2007. Chesapeake is
currently using 14 operated rigs to further develop its 585,000 net
acres of Core Fayetteville leasehold and anticipates operating up to
23 rigs by year-end 2008. Assuming an additional 5,400 net wells are
drilled in the years ahead, the company's estimated risked unproved
reserves in the play are 9.6 tcfe (13.0 tcfe of unrisked unproved
reserves). The table below highlights operational results over the
past five quarters from Chesapeake's operated wells in the
Fayetteville Shale play.
Number of Wells Average Average
Placed on Peak Rate (1) Lateral Length
Quarter Production (mcfe/d) (feet)
----------------------------------------------------------------------
2007 Q1 9 1,750 3,105
2007 Q2 13 2,045 2,856
2007 Q3 29 1,863 2,825
2007 Q4 37 1,933 3,011
2008 Q1 36 2,410 3,363
----------------------------------------------------------------------
Total / Weighted Average 124 2,053 3,060
----------------------------------------------------------------------
(1) Peak rate defined as the highest production rate of a well
over a 24-hour period
Haynesville Shale (Ark-La-Tex Region): Chesapeake recently
announced a significant discovery in the Haynesville Shale in the
Ark-La-Tex region. Based on its geoscientific, petrophysical and
engineering research during the past two years, including analysis of
over 50 wells drilled through the formation by others in the industry,
as well as the results of four horizontal and four vertical wells it
has drilled to date, Chesapeake believes the Haynesville Shale play
could potentially have a larger impact on the company than any other
play in which it has participated. Chesapeake is currently using four
operated rigs to further develop its 300,000 net acres of Haynesville
Shale leasehold and anticipates operating up to 12 rigs by year-end
2008 and up to 20 rigs by year-end 2009. The company has an aggressive
leasehold acquisition effort underway that has added 100,000 net acres
during the past five weeks and plans to add an additional 200,000 net
acres over time.
Marcellus Shale (West Virginia, Pennsylvania and New York):
Chesapeake is the largest leasehold owner in the Marcellus play that
spans from West Virginia to southern New York. The company is
currently using three operated rigs to further develop its 1.2 million
net acres of Marcellus Shale leasehold. Chesapeake is in the beginning
phases of significantly ramping up its Marcellus Shale drilling
activity and plans to lease at least another 200,000 net acres over
time. Assuming 1,350 net wells are drilled in the years ahead,
Chesapeake's estimated risked unproved reserves are approximately 1.9
tcfe (12.8 tcfe of unrisked unproved reserves).
Company Agrees to Sell 94 Bcfe of Proved Reserves for Proceeds of
$623 Million, or $6.63 per Mcfe, in its Second Volumetric Production
Payment Transaction
The company has recently agreed to sell certain
Chesapeake-operated long-lived producing assets in Texas, Oklahoma and
Kansas in its second volumetric production payment transaction.
Chesapeake will sell assets with proved reserves of approximately 94
bcfe and current net production of approximately 47 mmcfe per day for
proceeds of $623 million, or $6.63 per mcfe. Chesapeake will retain
drilling rights on the properties below currently producing intervals.
For accounting purposes, the transaction will be treated as a sale and
the company's proved reserves will be reduced accordingly. The
transaction is expected to close today. Chesapeake also plans to
pursue occasional undeveloped leasehold sales to high-grade its
inventory and further monetizations of mature producing properties as
needs and opportunities arise.
Company Announces Plans to Sell Remaining Arkoma Basin Woodford
Shale Properties for Anticipated Proceeds of Over $1.5 Billion
As part of high-grading its leasehold inventory and in order to
redeploy capital to higher priority areas in the company's operations,
Chesapeake has announced its intention to sell all of its remaining
Arkoma Basin Woodford Shale properties in Hughes, Pittsburg, Coal and
Atoka counties in Oklahoma. The properties consist of approximately
85,000 net acres, 40 mmcfe per day of current production and over 2.0
tcfe of potential net reserves. The company expects to receive
proceeds of over $1.5 billion from the sale of the properties and
anticipates completing a transaction in mid-2008. Chesapeake has
retained Meagher Oil & Gas Properties, Inc. to assist in the sale of
the properties.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief Executive Officer,
commented, "We are pleased to report our financial and operational
results for the 2008 first quarter. We are especially proud of our 31%
increase in average daily production in the 2008 first quarter
compared to the 2007 first quarter and by our adjusted net income per
share increasing by 25% to an all-time record level. This is strong
evidence that our rapid production growth is translating into
proportional gains in per-share net income despite inflationary
pressure on the industry's cost structure. By investing early in new
plays and through our strong technical skills and aggressive cost
control measures, we have been able to deliver substantial per-share
value to shareholders.
"We are also pleased with our growth in proved reserves and
believe that we are on track to reach 13 tcfe of proved reserves by
year-end 2008 and 15 tcfe by year-end 2009. In addition, our new
Haynesville Shale play continues to look very promising and our
acreage acquisition efforts there remain successful. We now own or
have commitments for over 300,000 net acres and maintain our goal of
reaching 500,000 net acres in the play over time. During the past
month, we brought on-line our fourth horizontal Haynesville Shale well
and it provides further support for our assessment of the play.
"Finally, our Barnett Shale, Fayetteville Shale and Marcellus
Shale plays continue to look very attractive and increasingly more
valuable. We now own approximately 260,000 net acres in the Barnett
Shale play, 585,000 net acres in the Core area of the Fayetteville
Shale play and 1.2 million net acres in the Marcellus Shale play.
Based on recent industry transactions and peer company valuations, we
believe the undeveloped acreage of these three plays, together with
our 300,000 net acres in the Haynesville Shale play, is worth more
than $25 billion. When added to the $32 billion of PV-10 of the
company's proved reserves, Chesapeake's assets now appear to be worth
at least $57 billion, without even considering the substantial value
of the company's non-shale leasehold and other non E&P assets. We are
excited about our progress and momentum to date, but are even more
enthusiastic about our company's ability in the future to produce
growing amounts of clean, affordable, abundant and American natural
gas to our customers and to deliver substantial value from our
continuing growth to our shareholders."
Conference Call Information
A conference call to discuss this release has been scheduled for
Friday morning, May 2, 2008, at 11:00 a.m. EDT. The telephone number
to access the conference call is 913-312-1419 or toll-free
800-776-0420. The passcode for the call is 2125846. We encourage those
who would like to participate in the call to dial the access number
between 10:50 and 11:00 a.m. EDT. For those unable to participate in
the conference call, a replay will be available for audio playback
from 2 p.m. EDT on May 2, 2008, and will run through midnight EDT on
Friday, May 16, 2008. The number to access the conference call replay
is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay
is 2125846. The conference call will also be webcast live on the
Internet and can be accessed by going to Chesapeake's website at
www.chk.com and selecting the "News & Events" section. The webcast of
the conference call will be available on our website for one year.
This press release and the accompanying Outlooks include
"forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. Forward-looking statements give our current expectations or
forecasts of future events. They include estimates of natural gas and
oil reserves, expected natural gas and oil production and future
expenses, projections of future natural gas and oil prices, planned
capital expenditures for drilling, leasehold acquisitions and seismic
data and planned asset sales, as well as statements concerning
anticipated cash flow and liquidity, business strategy and other plans
and objectives for future operations. Disclosures concerning the fair
value of derivative contracts and their estimated contribution to our
future results of operations are based upon market information as of a
specific date. These market prices are subject to significant
volatility. We caution you not to place undue reliance on our
forward-looking statements, which speak only as of the date of this
press release, and we undertake no obligation to update this
information.
Factors that could cause actual results to differ materially from
expected results are described in "Risk Factors" in Item 1A of our
Annual Report on Form 10-K for the year ended December 31, 2007, filed
with the U.S. Securities and Exchange Commission on February 29, 2008.
These risk factors include the volatility of natural gas and oil
prices; the limitations our level of indebtedness may have on our
financial flexibility; our ability to compete effectively against
strong independent natural gas and oil companies and majors; the
availability of capital on an economic basis, including planned asset
monetization transactions, to fund reserve replacement costs; our
ability to replace reserves and sustain production; uncertainties
inherent in estimating quantities of natural gas and oil reserves and
projecting future rates of production and the amount and timing of
development expenditures; uncertainties in evaluating natural gas and
oil reserves of acquired properties and associated potential
liabilities; our ability to effectively consolidate and integrate
acquired properties and operations; unsuccessful exploration and
development drilling; declines in the values of our natural gas and
oil properties resulting in ceiling test write-downs; lower prices
realized on natural gas and oil sales and collateral required to
secure hedging liabilities resulting from our commodity price risk
management activities; the negative impact lower natural gas and oil
prices could have on our ability to borrow; drilling and operating
risks, including potential environmental liabilities; production
interruptions that could adversely affect our cash flow; and pending
or future litigation.
Our production forecasts are dependent upon many assumptions,
including estimates of production decline rates from existing wells
and the outcome of future drilling activity. Although we believe the
expectations and forecasts reflected in these and other
forward-looking statements are reasonable, we can give no assurance
they will prove to have been correct. They can be affected by
inaccurate assumptions or by known or unknown risks and uncertainties.
The SEC has generally permitted natural gas and oil companies, in
filings made 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 the term "unproved" to
describe volumes of reserves potentially recoverable through
additional drilling or recovery techniques that the SEC's guidelines
may prohibit us from including in filings with the SEC. These
estimates are by their nature more speculative than estimates of
proved reserves and accordingly are subject to substantially greater
risk of actually being realized by the company. While we believe our
calculations of unproved drillsites and estimation of unproved
reserves have been appropriately risked and are reasonable, such
calculations and estimates have not been reviewed by third-party
engineers or appraisers.
Chesapeake Energy Corporation is the third-largest producer of
natural gas in the U.S. Headquartered in Oklahoma City, the company's
operations are focused on exploratory and developmental drilling and
corporate and property acquisitions in the Fort Worth Barnett Shale,
Fayetteville Shale, Haynesville Shale, Mid-Continent, Appalachian
Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast
and Ark-La-Tex regions of the United States. Chesapeake's Internet
address is www.chk.com.
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per-share and unit data)
(unaudited)
======================================================================
March 31, March 31,
THREE MONTHS ENDED: 2008 2007
----------------------------------------------------------------------
$ $/mcfe $ $/mcfe
--------- -------- --------- --------
REVENUES:
Natural gas and oil sales 773 3.78 1,125 7.31
Natural gas and oil
marketing sales 796 3.90 422 2.75
Service operations revenue 42 0.21 33 0.22
--------- -------- --------- --------
Total Revenues 1,611 7.89 1,580 10.28
--------- -------- --------- --------
OPERATING COSTS:
Production expenses 201 0.98 142 0.93
Production taxes 75 0.37 42 0.27
General and administrative
expenses 79 0.39 52 0.34
Natural gas and oil
marketing expenses 774 3.79 407 2.65
Service operations expense 35 0.17 22 0.14
Natural gas and oil
depreciation, depletion and
amortization 515 2.52 393 2.56
Depreciation and
amortization of other
assets 36 0.18 36 0.23
--------- -------- --------- --------
Total Operating Costs 1,715 8.40 1,094 7.12
--------- -------- --------- --------
INCOME (LOSS) FROM OPERATIONS (104) (0.51) 486 3.16
--------- -------- --------- --------
OTHER INCOME (EXPENSE):
Interest and other income (9) (0.04) 9 0.06
Interest expense (101) (0.50) (79) (0.51)
--------- -------- --------- --------
Total Other Income
(Expense) (110) (0.54) (70) (0.45)
--------- -------- --------- --------
INCOME (LOSS) BEFORE INCOME
TAXES (214) (1.05) 416 2.71
Income Tax Expense
(Benefit):
Current -- -- -- --
Deferred (82) (0.40) 158 1.03
--------- -------- --------- --------
Total Income Tax Expense
(Benefit) (82) (0.40) 158 1.03
--------- -------- --------- --------
NET INCOME (LOSS) (132) (0.65) 258 1.68
--------- -------- --------- --------
Preferred stock dividends (11) (0.05) (26) (0.17)
--------- -------- --------- --------
NET INCOME (LOSS) AVAILABLE TO
COMMON SHAREHOLDERS (143) (0.70) 232 1.51
========= ======== ========= ========
EARNINGS (LOSS) PER COMMON
SHARE:
Basic $ (0.29) $ 0.51
========= =========
Assuming dilution $ (0.29) $ 0.50
========= =========
WEIGHTED AVERAGE COMMON AND
COMMON
EQUIVALENT SHARES OUTSTANDING
(in millions)
Basic 493 451
========= =========
Assuming dilution 493 516
========= =========
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
======================================================================
March 31, December 31,
2008 2007
----------------------------------------------------------------------
Cash $ 1 $ 1
Other current assets 1,945 1,395
------------- ------------
Total Current Assets 1,946 1,396
------------- ------------
Property and equipment (net) 30,519 28,337
Other assets 997 1,001
------------- ------------
Total Assets $ 33,462 $ 30,734
============= ============
Current liabilities $ 4,220 $ 2,761
Long-term debt, net 12,250 10,950
Asset retirement obligation 243 236
Other long-term liabilities 1,203 691
Deferred tax liability 4,076 3,966
------------- ------------
Total Liabilities 21,992 18,604
Stockholders' Equity 11,470 12,130
------------- ------------
Total Liabilities & Stockholders' Equity $ 33,462 $ 30,734
============= ============
Common Shares Outstanding (in millions) 514 511
============= ============
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
======================================================================
% of Total % of Total
March 31, Book December 31, Book
2008 Capitalization 2007 Capitalization
----------------------------------------------------------------------
Long-term debt,
net $ 12,250 52% $ 10,950 47%
Stockholders'
equity 11,470 48% 12,130 53%
--------- -------------- ------------ --------------
Total $ 23,720 100% $ 23,080 100%
========= ============== ============ ==============
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2008 ADDITIONS TO NATURAL GAS AND OIL PROPERTIES
($ in millions, except per-unit data)
(unaudited)
======================================================================
Reserves
Cost (in bcfe) $/mcfe
----------------------------------------------------------------------
Exploration and development costs $ 1,374 686(a) 2.00
Acquisition of proved properties 63 39 1.59
Sale of proved properties (86) (32) (2.72)
---------- ----------- --------
Drilling and net acquisition
cost 1,351 693 1.95
---------- ----------- --------
Revisions - price -- 112 --
Acquisition of unproved properties
and leasehold 853 -- --
Sale of unproved properties and
leasehold (159) -- --
---------- ----------- --------
Net leasehold and unproved
property acquisition 694 -- --
---------- ----------- --------
Capitalized interest on leasehold
and unproved property 80 -- --
Geological and geophysical costs 84 -- --
---------- ----------- --------
Geologic, geophysical and
capitalized interest 164 -- --
---------- ----------- --------
Subtotal 2,209 805 2.74
---------- ----------- --------
Tax basis step-up 13 -- --
Asset retirement obligation and
other 3 -- --
---------- ----------- --------
Total $ 2,225 805 2.76
========== =========== --------
(a) Includes 365 bcfe of positive performance revisions (342 bcfe
relating to infill drilling and increased density locations and 23
bcfe of other performance related revisions) and excludes positive
revisions of 112 bcfe resulting from natural gas and oil price
increases between December 31, 2007, and March 31, 2008.
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
THREE MONTHS ENDED MARCH 31, 2008
(unaudited)
======================================================================
Bcfe
----------------------------------------------------------------------
Beginning balance, 01/01/08 10,879
Extensions and discoveries 321
Acquisitions 39
Divestitures (32)
Revisions - performance 365
Revisions - price 112
Production (204)
----------
Ending balance, 3/31/08 11,480
==========
Reserve replacement 805
Reserve replacement ratio (a) 395%
(a) The company uses the reserve replacement ratio as an indicator
of the company's ability to replenish annual production volumes and
grow its reserves. It should be noted that the reserve replacement
ratio is a statistical indicator that has limitations. The ratio 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 the ratio does not embed the cost or timing of future
production of new reserves, it cannot be used as a measure of value
creation.
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - NATURAL GAS AND OIL SALES AND INTEREST EXPENSE
(unaudited)
THREE MONTHS ENDED
March 31,
---------------------
2008 2007
---------- ---------
Natural Gas and Oil Sales ($ in millions):
Natural gas sales $ 1,432 $ 888
Natural gas derivatives - realized gains
(losses) 268 415
Natural gas derivatives - unrealized gains
(losses) (1,002) (297)
---------- ---------
Total Natural Gas Sales 698 1,006
---------- ---------
Oil sales 258 113
Oil derivatives - realized gains (losses) (53) 18
Oil derivatives - unrealized gains (losses) (130) (12)
---------- ---------
Total Oil Sales 75 119
---------- ---------
Total Natural Gas and Oil Sales $ 773 $ 1,125
========== =========
Average Sales Price - excluding gains (losses)
on derivatives:
Natural gas ($ per mcf) $ 7.63 $ 6.31
Oil ($ per bbl) $ 94.14 $ 52.80
Natural gas equivalent ($ per mcfe) $ 8.28 $ 6.52
Average Sales Price - excluding unrealized gains
(losses)
on derivatives):
Natural gas ($ per mcf) $ 9.05 $ 9.26
Oil ($ per bbl) $ 74.73 $ 61.13
Natural gas equivalent ($ per mcfe) $ 9.33 $ 9.33
Interest Expense ($ in millions):
Interest $ 88 $ 76
Derivatives - realized (gains) losses -- 2
Derivatives - unrealized (gains) losses 13 1
---------- ---------
Total Interest Expense $ 101 $ 79
========== =========
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
======================================================================
March 31, March 31,
THREE MONTHS ENDED: 2008 2007
----------------------------------------------------------------------
Beginning cash $ 1 $ 3
Cash provided by operating activities 1,498 977
Cash (used in) investing activities (2,675) (1,869)
Cash provided by financing activities 1,177 893
Ending cash 1 4
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
======================================================================
March 31, December 31, March 31,
THREE MONTHS ENDED: 2008 2007 2007
----------------------------------------------------------------------
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,498 $ 1,544 $ 977
Adjustments:
Changes in assets and liabilities 14 (222) 147
--------- ------------ ---------
OPERATING CASH FLOW(a) $ 1,512 $ 1,322 $ 1,124
========= ============ =========
(a) Operating cash flow represents net cash provided by operating
activities before changes in assets and liabilities. Operating cash
flow is presented because management believes it is a useful adjunct
to net cash provided by operating activities under accounting
principles generally accepted in the United States (GAAP). Operating
cash flow is widely accepted as a financial indicator of a natural gas
and oil company's ability to generate cash which is used to internally
fund exploration and development activities and to service debt. This
measure is widely used by investors and rating agencies in the
valuation, comparison, rating and investment recommendations of
companies within the natural gas and oil exploration and production
industry. Operating cash flow is not a measure of financial
performance under GAAP and should not be considered as an alternative
to cash flows from operating, investing, or financing activities as an
indicator of cash flows, or as a measure of liquidity.
March 31, December 31, March 31,
THREE MONTHS ENDED: 2008 2007 2007
----------------------------------------------------------------------
NET INCOME (LOSS) $ (132) $ 303 $ 258
Income tax expense (benefit) (82) 186 158
Interest expense 101 128 79
Depreciation and amortization of
other assets 36 33 36
Natural gas and oil depreciation,
depletion and amortization 515 521 393
--------- ------------ ---------
EBITDA(b) $ 438 $ 1,171 $ 924
========= ============ =========
(b) Ebitda represents net income (loss) before income tax expense,
interest expense, and depreciation, depletion and amortization
expense. Ebitda is presented as a supplemental financial measurement
in the evaluation of our business. We believe that it provides
additional information regarding our ability to meet our future debt
service, capital expenditures and working capital requirements. This
measure is widely used by investors and rating agencies in the
valuation, comparison, rating and investment recommendations of
companies. Ebitda is also a financial measurement that, with certain
negotiated adjustments, is reported to our lenders pursuant to our
bank credit agreement and is used in the financial covenants in our
bank credit agreement and our senior note indentures. Ebitda is not a
measure of financial performance under GAAP. Accordingly, it should
not be considered as a substitute for net income, income from
operations, or cash flow provided by operating activities prepared in
accordance with GAAP. Ebitda is reconciled to cash provided by
operating activities as follows:
March 31, December 31, March 31,
THREE MONTHS ENDED: 2008 2007 2007
----------------------------------------------------------------------
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,498 $ 1,544 $ 977
Changes in assets and liabilities 14 (222) 147
Interest expense 101 128 79
Unrealized gains (losses) on natural
gas and oil derivatives (1,132) (261) (310)
Other non-cash items (43) (18) 31
--------- ------------ ---------
EBITDA $ 438 $ 1,171 $ 924
========= ============ =========
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
($ in millions, except per-share data)
(unaudited)
======================================================================
March 31, December 31, March 31,
THREE MONTHS ENDED: 2008 2007 2007
----------------------------------------------------------------------
Net income (loss) available to common
shareholders $ (143) $ 158 $ 232
Adjustments:
Unrealized (gains) losses on
derivatives, net of tax 704 180 193
Loss on conversion/exchange of
preferred stock -- 128 --
--------- ------------ ---------
Adjusted net income available to
common shareholders(1) 561 466 425
Preferred stock dividends 11 17 26
--------- ------------ ---------
Total adjusted net income $ 572 $ 483 $ 451
========= ============ =========
Weighted average fully diluted shares
outstanding(2) 524 520 516
Adjusted earnings per share assuming
dilution $ 1.09 $ 0.93 $ 0.87
========= ============ =========
(1) Adjusted net income available to common and adjusted earnings
per share assuming dilution exclude certain items that management
believes affect the comparability of operating results. The company
discloses these non-GAAP financial measures as a useful adjunct to
GAAP earnings because:
(a) Management uses adjusted net income available to common to
evaluate the company's operational trends and performance relative to
other natural gas and oil producing companies.
(b) Adjusted net income available to common is more comparable to
earnings estimates provided by securities analysts.
(c) Items excluded generally are one-time items or items whose
timing or amount cannot be reasonably estimated. Accordingly, any
guidance provided by the company generally excludes information
regarding these types of items.
(2) Weighted average fully diluted shares outstanding include
shares that were considered antidilutive for calculating earnings per
share in accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
March 31, December 31, March 31,
THREE MONTHS ENDED: 2008 2007 2007
----------------------------------------------------------------------
EBITDA $ 438 $ 1,171 $ 924
Adjustments, before tax:
Unrealized (gains) losses on
natural gas and oil derivatives 1,132 261 310
--------- ------------ ---------
Adjusted ebitda(1) $ 1,570 $ 1,432 $ 1,234
========= ============ =========
(1) Adjusted ebitda excludes certain items that management
believes affect the comparability of operating results. The company
discloses these non-GAAP financial measures as a useful adjunct to
ebitda because:
(a) Management uses adjusted ebitda to evaluate the company's
operational trends and performance relative to other natural gas and
oil producing companies.
(b) Adjusted ebitda is more comparable to estimates provided by
securities analysts.
(c) Items excluded generally are one-time items or items whose
timing or amount cannot be reasonably estimated. Accordingly, any
guidance provided by the company generally excludes information
regarding these types of items.
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF MAY 1, 2008
Quarter Ending June 30, 2008 and Years Ending December 31, 2008,
2009 and 2010.
We have adopted a policy of periodically providing guidance on
certain factors that affect our future financial performance. As of
May 1, 2008, we are using the following key assumptions in our
projections for the second quarter of 2008 and the full years 2008,
2009 and 2010.
The primary changes from our March 31, 2008 Outlook are in
italicized bold and are explained as follows:
1) Our first guidance for the 2008 second quarter and the full
year 2010 has been provided;
2) Production guidance has been updated for full years 2008 and
2009;
3) Projected effects of changes in our hedging positions have been
updated;
4) Certain cost assumptions and budgeted capital expenditure
assumptions have been updated; and
5) Shares outstanding have been updated to reflect the exercise of
the over-allotment option in our recent common stock offering and to
incorporate the effects of our contingently convertible notes.
Quarter Ending Year Ending
6/30/2008 12/31/2008
-------------- -----------------
Estimated Production(a)
Natural gas - bcf 190 - 192 791 - 801
Oil - mbbls 2,700 11,000
Natural gas equivalent - bcfe 206 - 208 857 - 867
Daily natural gas equivalent
midpoint - mmcfe 2,275 2,360
Year-over-year production increase 22% 21%
NYMEX Prices (b) (for calculation of
realized hedging effects only):
Natural gas - $/mcf $8.53 $8.14
Oil - $/bbl $80.00 $84.48
Estimated Realized Hedging Effects
(based on assumed NYMEX prices
above):
Natural gas - $/mcf $0.50 $1.17
Oil - $/bbl $(4.66) $(7.47)
Estimated Differentials to NYMEX
Prices:
Natural gas - $/mcf 10 - 14% 10 - 14%
Oil - $/bbl 7 - 9% 7 - 9%
Operating Costs per Mcfe of Projected
Production:
Production expense $0.95 - 1.05 $0.95 - 1.05
Production taxes (about 5% of O&G
revenues) (c) $0.35 - 0.40 $0.35 - 0.40
General and administrative(d) $0.33 - 0.37 $0.33 - 0.37
Stock-based compensation (non-
cash) $0.08 - 0.10 $0.10 - 0.12
DD&A of natural gas and oil assets $2.50 - 2.70 $2.50 - 2.70
Depreciation of other assets $0.20 - 0.24 $0.20 - 0.24
Interest expense(e) $0.50 - 0.55 $0.50 - 0.55
Other Income per Mcfe:
Natural gas and oil marketing
income $0.09 - 0.11 $0.09 - 0.11
Service operations income $0.04 - 0.06 $0.04 - 0.06
Book Tax Rate 38.5% 38.5%
Equivalent Shares Outstanding - in
millions:
Basic 519 514
Diluted 556 550
Budgeted E&P Capital Expenditures,
net - in millions:
Drilling $1,300 - 1,500 $5,500 - 6,000
Acquisition of leasehold and
producing properties $600 - 800 $2,100 - 2,600
Sale of leasehold and producing
properties(a) $(625) $(2,975 - 3,225)
Geological and geophysical costs $75 $300
-------------- -----------------
Total budgeted E&P capital
expenditures, net $1,350 - 1,750 $4,925 - $5,675
============== =================
Year Ending Year Ending
12/31/2009 12/31/2010
---------------- ----------------
Estimated Production(a)
Natural gas - bcf 918 - 938 1,052 - 1,092
Oil - mbbls 12,000 13,000
Natural gas equivalent - bcfe 990 - 1,010 1,130 -1,170
Daily natural gas equivalent
midpoint - mmcfe 2,740 3,150
Year-over-year production
increase 16% 15%
NYMEX Prices (b) (for calculation
of realized hedging effects only):
Natural gas - $/mcf $8.00 $8.00
Oil - $/bbl $80.00 $80.00
Estimated Realized Hedging Effects
(based on assumed NYMEX prices
above):
Natural gas - $/mcf $0.93 $0.40
Oil - $/bbl $1.78 $4.34
Estimated Differentials to NYMEX
Prices:
Natural gas - $/mcf 10 - 14% 10 - 14%
Oil - $/bbl 7 - 9% 7 - 9%
Operating Costs per Mcfe of
Projected Production:
Production expense $1.00 - 1.10 $1.05 - 1.15
Production taxes (about 5% of
O&G revenues) (c) $0.35 - 0.40 $0.35 - 0.40
General and administrative(d) $0.33 - 0.37 $0.33 - 0.37
Stock-based compensation (non-
cash) $0.10 - 0.12 $0.10 - 0.12
DD&A of natural gas and oil
assets $2.50 - 2.70 $2.50 - 2.70
Depreciation of other assets $0.20 - 0.24 $0.20 - 0.24
Interest expense(e) $0.50 - 0.55 $0.50 - 0.55
Other Income per Mcfe:
Natural gas and oil marketing
income $0.09 - 0.11 $0.09 - 0.11
Service operations income $0.04 - 0.06 $0.04 - 0.06
Book Tax Rate 38.5% 38.5%
Equivalent Shares Outstanding - in
millions:
Basic 529 541
Diluted 564 572
Budgeted E&P Capital Expenditures,
net - in millions:
Drilling $5,750 - 6,250 $6,000 - 6,500
Acquisition of leasehold and
producing properties $1,500 - 2,000 $1,500 -2,000
Sale of leasehold and producing
properties(a) $(1,000 - 1,500) $(1,000 - 1,500)
Geological and geophysical costs $300 $300
---------------- ----------------
Total budgeted E&P capital
expenditures, net $6,550 - $7,050 $6,800 - $7,300
================ ================
(a) The 2008 and 2009 forecasts assume that the company sells: 1)
producing properties for $625 million in the 2008 second quarter in a
volumetric production payment (VPP) transaction; 2) Arkoma Basin
properties for $1.50 - 1.75 billion in the 2008 third quarter; 3)
undeveloped leasehold or producing properties for $600 million in the
2008 second half; and 4) undeveloped leasehold or producing properties
for $1.0-1.5 billion in each of 2009 and 2010.
(b) NYMEX oil prices have been updated for actual contract prices
through March 2008 and NYMEX natural gas prices have been updated for
actual contract prices through April 2008.
(c) Severance tax per mcfe is based on NYMEX prices of: $80.00 per
bbl of oil and $7.40 to $8.70 per mcf of natural gas during Q2 2008;
$84.48 per bbl of oil and $7.60 to $8.90 per mcf of natural gas during
calendar 2008; and $80.00 per bbl of oil and $7.80 to $9.10 per mcf of
natural gas during calendar 2009 and 2010.
(d) Excludes expenses associated with non-cash stock compensation.
(e) Does not include gains or losses on interest rate derivatives
(SFAS 133).
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a
portion of its future natural gas and oil production. These strategies
include:
(i) For swap instruments, Chesapeake receives a fixed price and
pays a floating market price to the counterparty. The fixed-price
payment and the floating-price payment are netted, resulting in a net
amount due to or from the counterparty.
(ii) Basis protection swaps are arrangements that guarantee a
price differential for oil or natural gas from a specified delivery
point. For Mid-Continent basis protection swaps, which have negative
differentials to NYMEX, Chesapeake receives a payment from the
counterparty if the price differential is greater than the stated
terms of the contract and pays the counterparty if the price
differential is less than the stated terms of the contract. For
Appalachian basis protection swaps, which have positive differentials
to NYMEX, Chesapeake receives a payment from the counterparty if the
price differential is less than the stated terms of the contract and
pays the counterparty if the price differential is greater than the
stated terms of the contract.
(iii) For knockout swaps, Chesapeake receives a fixed price and
pays a floating market price. The fixed price received by Chesapeake
includes a premium in exchange for the possibility to reduce the
counterparty's exposure to zero, in any given month, if the floating
market price is lower than certain predetermined knockout prices.
(iv) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake includes
a premium in exchange for a "cap" limiting the counterparty's
exposure. In other words, there is no limit to Chesapeake's exposure
but there is a limit to the downside exposure of the counterparty
(v) For written call options, Chesapeake receives a premium from
the counterparty in exchange for the sale of a call option. If the
market price exceeds the fixed price of the call option, Chesapeake
pays the counterparty such excess. If the market price settles below
the fixed price of the call option, no payment is due from Chesapeake.
(vi) Collars contain a fixed floor price (put) and ceiling price
(call). If the market price exceeds the call strike price or falls
below the put strike price, Chesapeake receives the fixed price and
pays the market price. If the market price is between the call and the
put strike price, no payments are due from either party.
(vii) A three-way collar contract consists of a standard collar
contract plus a written put option with a strike price below the floor
price of the collar. In addition to the settlement of the collar, the
put option requires Chesapeake to make a payment to the counterparty
equal to the difference between the put option price and the
settlement price if the settlement price for any settlement period is
below the put option strike price.
Commodity markets are volatile, and as a result, Chesapeake's
hedging activity is dynamic. As market conditions warrant, the company
may elect to settle a hedging transaction prior to its scheduled
maturity date and lock in the gain or loss on the transaction.
Chesapeake enters into natural gas and oil derivative transactions
in order to mitigate a portion of its exposure to adverse market
changes in natural gas and oil prices. Accordingly, associated gains
or losses from the derivative transactions are reflected as
adjustments to natural gas and oil sales. All realized gains and
losses from natural gas and oil derivatives are included in natural
gas and oil sales in the month of related production. Pursuant to SFAS
133, certain derivatives do not qualify for designation as cash flow
hedges. Changes in the fair value of these nonqualifying derivatives
that occur prior to their maturity (i.e., because of temporary
fluctuations in value) are reported currently in the consolidated
statement of operations as unrealized gains (losses) within natural
gas and oil sales.
Following provisions of SFAS 133, changes in the fair value of
derivative instruments designated as cash flow hedges, to the extent
effective in offsetting cash flows attributable to hedged risk, are
recorded in other comprehensive income until the hedged item is
recognized in earnings. Any change in fair value resulting from
ineffectiveness is recognized currently in natural gas and oil sales.
Excluding the swaps assumed in connection with the acquisition of
CNR which are described below, the company currently has the following
open natural gas swaps in place and also has the following gains from
lifted natural gas swaps:
Open Swap Total
Positions Lifted
as a Total Gain
Avg. % of Gains per Mcf of
NYMEX Assuming Estimated from Estimated
Open Strike Natural Gas Total Lifted Total
Swaps Price Production Natural Swaps Natural
in of Open in Bcf's Gas ($ Gas
Bcf's Swaps of: Production millions) Production
======================================================================
Q2 2008 139.4 $8.66 191 73% $40.2 $0.21
Q3 2008 150.0 $8.97 203 74% $39.3 $0.19
Q4 2008 142.6 $9.53 214 67% $50.2 $0.23
======================================================================
Q2-Q4
2008(1) 432.0 $9.05 608 71% $129.7 $0.21
======================================================================
======================================================================
Total
2009(1) 467.6 $9.44 928 50% $32.6 $0.04
======================================================================
======================================================================
Total
2010(1) 214.5 $9.56 1,072 20% $(4.2) $0.00
======================================================================
(1) Certain hedging arrangements include cap-swaps and knockout
swaps with provisions limiting the counterparty's exposure below
prices ranging from $5.45 to $6.50 covering 187 bcf in 2008, 5.45 to
$7.25 covering 332 bcf in 2009 and $5.45 to $7.25 covering 172 bcf in
2010.
The company currently has the following open natural gas collars
in place:
Open Collars
Assuming as a % of
Avg. Natural Gas Estimated
Open NYMEX Avg. NYMEX Production Total
Collars Floor Ceiling in Bcf's Natural Gas
in Bcf's Price Price of: Production
======================================================================
Q2 2008 10.9 $8.27 $9.92 191 6%
Q3 2008 11.0 $8.27 $9.92 203 5%
Q4 2008 9.2 $8.20 $9.91 214 4%
======================================================================
Q2-Q4 2008 31.1 $8.25 $9.92 608 5%
======================================================================
======================================================================
Total 2009(1) 45.7 $8.14 $10.82 928 5%
======================================================================
======================================================================
Total 2010(1) 3.7 $7.30 $12.00 1,072 0%
======================================================================
(1) Certain collar arrangements include three-way collars that
include written put options with strike prices ranging from $5.50 to
$6.00 covering 46 bcf in 2009 and at $6.00 covering 4 bcf in 2010.
Note: Not shown above are written call options covering 128 bcf of
production in 2008 at a weighed average price of $10.16 for a weighted
average premium of $0.68, 178 bcf of production in 2009 at a weighed
average price of $11.29 for a weighted average premium of $0.50 and
161 bcf of production in 2010 at a weighed average price of $10.71 for
a weighted average premium of $0.60.
The company has the following natural gas basis protection swaps
in place:
Mid-Continent Appalachia
------------------------- ---------------------------
Volume in NYMEX Volume in NYMEX
Bcf's less(a): Bcf's plus(a):
----------- ------------- ------------- -------------
2008 132.4 0.36 23.0 0.33
2009 91.1 0.33 16.9 0.28
2010 -- -- 10.2 0.26
2011 -- -- 12.1 0.25
2012 10.7 0.34 -- --
----------- ------------- ------------- -------------
Totals 234.2 $ 0.35 62.2 $ 0.29
=========== ============= ============= =============
(a) weighted average
We assumed certain liabilities related to open derivative
positions in connection with the CNR acquisition in November 2005. In
accordance with SFAS 141, these derivative positions were recorded at
fair value in the purchase price allocation as a liability of $592
million ($128 million as of March 31, 2008). The recognition of the
derivative liability and other assumed liabilities resulted in an
increase in the total purchase price which was allocated to the assets
acquired. Because of this accounting treatment, only cash settlements
for changes in fair value subsequent to the acquisition date for the
derivative positions assumed result in adjustments to our natural gas
and oil revenues upon settlement. For example, if the fair value of
the derivative positions assumed does not change, then upon the sale
of the underlying production and corresponding settlement of the
derivative positions, cash would be paid to the counterparties and
there would be no adjustment to natural gas and oil revenues related
to the derivative positions. If, however, the actual sales price is
different from the price assumed in the original fair value
calculation, the difference would be reflected as either a decrease or
increase in natural gas and oil revenues, depending upon whether the
sales price was higher or lower, respectively, than the prices assumed
in the original fair value calculation. For accounting purposes, the
net effect of these acquired hedges is that we hedged the production
volumes listed below at their fair values on the date of our
acquisition of CNR.
Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative
Instruments and Hedging Activities," the assumed CNR derivative
instruments are deemed to contain a significant financing element and
all cash flows associated with these positions are reported as
financing activity in the statement of cash flows.
The following details the CNR derivatives (natural gas swaps) we
have assumed:
Open Swap
Avg. Positions
NYMEX as a %
Strike Avg. Fair Assuming of
Price Value Upon Natural Estimated
Open Of Open Acquisition Initial Gas Total
Swaps Swaps of Liability Production Natural
in (per Open Swaps Acquired in Bcf's Gas
Bcf's Mcf) (per Mcf) (per Mcf) of: Production
----------------------------------------------------------------------
Q2 2008 9.6 $4.68 $7.41 ($2.73) 191 5%
Q3 2008 9.7 $4.68 $7.41 ($2.74) 203 5%
Q4 2008 9.7 $4.66 $7.84 ($3.17) 214 5%
======================================================================
Q2-Q4 2008 29.0 $4.67 $7.55 ($2.88) 608 5%
======================================================================
======================================================================
Total 2009 18.3 $5.18 $7.28 ($2.10) 928 2%
======================================================================
Note: Not shown above are collars covering 3.7 bcf of production
in 2009 at an average floor and ceiling of $4.50 and $6.00.
The company also has the following crude oil swaps in place:
Open Swap Total Total
Positions Losses Lifted
Assuming as a % from Losses per
Avg. Oil of Lifted bbl of
Open NYMEX Production Estimated Swaps Estimated
Swaps Strike in mbbls Total Oil ($ Total Oil
in mbbls Price of: Production millions) Production
----------------------------------------------------------------------
Q2 2008 1,896 75.58 2,700 70% $(4.7) $(1.75)
Q3 2008 2,039 76.92 2,730 75% $(4.6) $(1.69)
Q4 2008 1,886 79.01 2,825 67% $(4.7) $(1.68)
======================================================================
Q2-Q4
2008(1) 5,821 $77.16 8,255 71% $(14.0) $(1.70)
======================================================================
======================================================================
Total
2009(1) 8,395 $82.33 12,000 70% -- --
======================================================================
======================================================================
Total
2010(1) 4,745 $90.25 13,000 37% -- --
======================================================================
(1) Certain hedging arrangements include cap-swaps and knockout
swaps with provisions limiting the counterparty's exposure below
prices ranging from $45.00 to $65.00 covering 3,423 mbbls in 2008,
from $52.50 to $60.00 covering 7,848 mbbls in 2009 and $60.00 covering
4,745 mbbls in 2010.
Note: Not shown above are written call options covering 2,109
mbbls of production in 2008 at a weighted average price of $82.82 for
a weighted average premium of $3.17, 2,555 mbbls of production in 2009
at a weighed average price of $82.14 for a weighted average premium of
$4.98 and 2,555 mbbls of production in 2010 at a weighed average price
of $96.43 for a weighted average premium of $3.79.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF MARCH 31, 2008
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF MAY 1, 2008
Quarter Ending March 31, 2008 and Years Ending December 31, 2008
and 2009.
We have adopted a policy of periodically providing guidance on
certain factors that affect our future financial performance. As of
March 31, 2008, we are using the following key assumptions in our
projections for the first quarter of 2008 and the full-years 2008 and
2009.
The primary changes from our February 21, 2008 Outlook are in
italicized bold and are explained as follows:
1) We are increasing our prior production guidance for the
full-years 2008 and 2009 (note: guidance in this Outlook excludes
production expected to be sold in conjunction with various anticipated
monetizations transactions in 2008 and 2009);
2) Projected effects of changes in our hedging positions have been
updated;
3) Budgeted capital expenditure assumptions have been updated; and
4) Share assumptions have been updated to reflect our recent 20
million share common stock offering.
Quarter Ending Year Ending Year Ending
3/31/2008 12/31/2008 12/31/2009
-------------- --------------- ---------------
Estimated Production(a)
Oil - mbbls 2,675 10,700 11,000
Natural gas - bcf 182 - 186 798 - 808 924 - 944
Natural gas
equivalent - bcfe 198 - 202 862.5 - 872.5 990 - 1,010
Daily natural gas
equivalent midpoint
- mmcfe 2,200 2,370 2,740
NYMEX Prices (b) (for
calculation of
realized hedging
effects only):
Oil - $/bbl $80.98 $82.36 $80.00
Natural gas - $/mcf $7.55 $8.01 $8.00
Estimated Realized
Hedging Effects (based
on assumed NYMEX
prices above):
Oil - $/bbl $(6.98) $(5.94) $1.94
Natural gas - $/mcf $1.84 $1.11 $0.69
Estimated Differentials
to NYMEX Prices:
Oil - $/bbl 7 - 9% 7 - 9% 7 - 9%
Natural gas - $/mcf 10 - 14% 10 - 14% 10 - 14%
Operating Costs per
Mcfe of Projected
Production:
Production expense $0.90 - 1.00 $0.90 - 1.00 $0.90 - 1.00
Production taxes
(generally 5% of
O&G revenues) (c) $0.32 - 0.37 $0.32 - 0.37 $0.32 - 0.37
General and
administrative(d) $0.33 - 0.37 $0.33 - 0.37 $0.33 - 0.37
Stock-based
compensation (non-
cash) $0.08 - 0.10 $0.10 - 0.12 $0.10 - 0.12
DD&A of oil and
natural gas assets $2.50 - 2.70 $2.50 - 2.70 $2.50 - 2.70
Depreciation of
other assets $0.20 - 0.24 $0.20 - 0.24 $0.20 - 0.24
Interest expense(e) $0.50 - 0.55 $0.50 - 0.55 $0.50 - 0.55
Other Income per Mcfe:
Oil and natural gas
marketing income $0.09 - 0.11 $0.09 - 0.11 $0.09 - 0.11
Service operations
income $0.04 - 0.06 $0.04 - 0.06 $0.04 - 0.06
Book Tax Rate (About
Equals 97% deferred) 38.5% 38.5% 38.5%
Equivalent Shares
Outstanding - in
millions:
Basic 493 509 523
Diluted 525 540 553
Budgeted Capital
Expenditures, net - in
millions:
Drilling $1,100 - 1,200 $4,600 - 5,000 $5,000 - 5,400
Leasehold and
property
acquisition costs $400 - 450 $1,300 - 1,500 $1,300 - 1,500
Monetization of oil
and gas
properties(a) -- $(1,000) $(1,000)
Geological and
geophysical costs $75 $250 $250
-------------- --------------- ---------------
Total budgeted
capital
expenditures,
net $1,575 - 1,725 $5,150 - $5,750 $5,550 - $6,150
(a) The 2008 and 2009 forecasts assume that the company monetizes
$2 billion of producing properties in multiple transactions in the
second and fourth quarters of 2008 and 2009.
(b) NYMEX oil prices have been updated for actual contract prices
through February 2008 and NYMEX natural gas prices have been updated
for actual contract prices through March 2008.
(c) Severance tax per mcfe is based on NYMEX prices of: $80.98 per
bbl of oil and $7.00 to $8.00 per mcf of natural gas during Q1 2008;
$82.36 per bbl of oil and $7.20 to $8.20 per mcf of natural gas during
calendar 2008; and $80.00 per bbl of oil and $7.30 to $8.30 per mcf of
natural gas during calendar 2009.
(d) Excludes expenses associated with non-cash stock compensation.
(e) Does not include gains or losses on interest rate derivatives
(SFAS 133).
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a
portion of its future oil and natural gas production. These strategies
include:
(i) For swap instruments, Chesapeake receives a fixed price and
pays a floating market price to the counterparty. The fixed-price
payment and the floating-price payment are netted, resulting in a net
amount due to or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake includes
a premium in exchange for a "cap" limiting the counterparty's
exposure. In other words, there is no limit to Chesapeake's exposure
but there is a limit to the downside exposure of the counterparty.
(iii) For knockout swaps, Chesapeake receives a fixed price and
pays a floating market price. The fixed price received by Chesapeake
includes a premium in exchange for the possibility to reduce the
counterparty's exposure to zero, in any given month, if the floating
market price is lower than certain predetermined knockout prices.
(iv) For written call options, Chesapeake receives a premium from
the counterparty in exchange for the sale of a call option. If the
market price exceeds the fixed price of the call option, Chesapeake
pays the counterparty such excess. If the market price settles below
the fixed price of the call option, no payment is due from Chesapeake.
(v) Collars contain a fixed floor price (put) and ceiling price
(call). If the market price exceeds the call strike price or falls
below the put strike price, Chesapeake receives the fixed price and
pays the market price. If the market price is between the call and the
put strike price, no payments are due from either party.
(vi) A three-way collar contract consists of a standard collar
contract plus a written put option with a strike price below the floor
price of the collar. In addition to the settlement of the collar, the
put option requires Chesapeake to make a payment to the counterparty
equal to the difference between the put option price and the
settlement price if the settlement price for any settlement period is
below the put option strike price.
(vii) Basis protection swaps are arrangements that guarantee a
price differential for oil or natural gas from a specified delivery
point. For Mid-Continent basis protection swaps, which have negative
differentials to NYMEX, Chesapeake receives a payment from the
counterparty if the price differential is greater than the stated
terms of the contract and pays the counterparty if the price
differential is less than the stated terms of the contract. For
Appalachian basis protection swaps, which have positive differentials
to NYMEX, Chesapeake receives a payment from the counterparty if the
price differential is less than the stated terms of the contract and
pays the counterparty if the price differential is greater than the
stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's
hedging activity is dynamic. As market conditions warrant, the company
may elect to settle a hedging transaction prior to its scheduled
maturity date and lock in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions
in order to mitigate a portion of its exposure to adverse market
changes in oil and natural gas prices. Accordingly, associated gains
or losses from the derivative transactions are reflected as
adjustments to oil and natural gas sales. All realized gains and
losses from oil and natural gas derivatives are included in oil and
natural gas sales in the month of related production. Pursuant to SFAS
133, certain derivatives do not qualify for designation as cash flow
hedges. Changes in the fair value of these nonqualifying derivatives
that occur prior to their maturity (i.e., because of temporary
fluctuations in value) are reported currently in the consolidated
statement of operations as unrealized gains (losses) within oil and
natural gas sales.
Following provisions of SFAS 133, changes in the fair value of
derivative instruments designated as cash flow hedges, to the extent
effective in offsetting cash flows attributable to hedged risk, are
recorded in other comprehensive income until the hedged item is
recognized in earnings. Any change in fair value resulting from
ineffectiveness is recognized currently in oil and natural gas sales.
Excluding the swaps assumed in connection with the acquisition of
CNR which are described below, the company currently has the following
open natural gas swaps in place and also has the following gains from
lifted natural gas swaps:
Open Swap Total
Positions Lifted
Avg. as a Total Gain
NYMEX Assuming % of Gains per Mcf of
Strike Natural Estimated from Estimated
Open Price Gas Total Lifted Total
Swaps of Production Natural Swaps Natural
in Open in Bcf's Gas ($ Gas
Bcf's Swaps of: Production millions) Production
======================================================================
Q1 2008 131.0 $8.59 184 71% $156.4 $0.85
Q2 2008 137.5 $8.62 195 71% $40.6 $0.21
Q3 2008 138.0 $8.80 208 66% $38.1 $0.18
Q4 2008 127.6 $9.34 216 59% $47.1 $0.22
======================================================================
Total
2008(1) 534.1 $8.83 803 67% $282.2 $0.35
======================================================================
======================================================================
Total
2009(1) 356.1 $9.22 934 38% $22.1 $0.02
======================================================================
(1) Certain hedging arrangements include cap-swaps and knockout
swaps with provisions limiting the counterparty's exposure below
prices ranging from $5.45 to $6.50 covering 190 bcf in 2008 and $5.45
to $6.50 covering 280 bcf in 2009.
The company currently has the following open natural gas collars
in place:
Open Collars
Assuming as a % of
Avg. Avg. Natural Gas Estimated
Open NYMEX NYMEX Production Total
Collars Floor Ceiling in Bcf's Natural Gas
in Bcf's Price Price of: Production
======================================================================
Q1 2008 18.5 $7.36 $9.28 184 10%
Q2 2008 9.1 $8.27 $9.91 195 5%
Q3 2008 9.2 $8.27 $9.91 208 4%
Q4 2008 7.4 $8.19 $9.88 216 3%
======================================================================
Total 2008(1) 44.2 $7.88 $9.64 803 6%
======================================================================
======================================================================
Total 2009(1) 56.7 $8.22 $10.70 934 6%
======================================================================
(1) Certain collar arrangements include three-way collars that
include written put options with strike prices ranging from $5.00 to
$6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 46 bcf in
2009.
Note: Not shown above are written call options covering 111 bcf of
production in 2008 at a weighed average price of $10.26 for a weighted
average premium of $0.66 and 191 bcf of production in 2009 at a
weighed average price of $11.24 for a weighted average premium of
$0.52.
The company has the following natural gas basis protection swaps
in place:
Mid-Continent Appalachia
------------------------- ---------------------------
Volume in NYMEX Volume in NYMEX
Bcf's less(a): Bcf's plus(a):
----------- ------------- ------------- -------------
2008 132.4 0.36 23.0 0.33
2009 91.1 0.33 16.9 0.28
2010 -- -- 10.2 0.26
2011 -- -- 12.1 0.25
2012 10.7 0.34 -- --
----------- ------------- ------------- -------------
Totals 234.2 $ 0.35 62.2 $ 0.29
=========== ============= ============= =============
(a) weighted average
We assumed certain liabilities related to open derivative
positions in connection with the CNR acquisition in November 2005. In
accordance with SFAS 141, these derivative positions were recorded at
fair value in the purchase price allocation as a liability of $592
million ($173 million as of December 31, 2007). The recognition of the
derivative liability and other assumed liabilities resulted in an
increase in the total purchase price which was allocated to the assets
acquired. Because of this accounting treatment, only cash settlements
for changes in fair value subsequent to the acquisition date for the
derivative positions assumed result in adjustments to our oil and
natural gas revenues upon settlement. For example, if the fair value
of the derivative positions assumed does not change, then upon the
sale of the underlying production and corresponding settlement of the
derivative positions, cash would be paid to the counterparties and
there would be no adjustment to oil and natural gas revenues related
to the derivative positions. If, however, the actual sales price is
different from the price assumed in the original fair value
calculation, the difference would be reflected as either a decrease or
increase in oil and natural gas revenues, depending upon whether the
sales price was higher or lower, respectively, than the prices assumed
in the original fair value calculation. For accounting purposes, the
net effect of these acquired hedges is that we hedged the production
volumes listed below at their fair values on the date of our
acquisition of CNR.
Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative
Instruments and Hedging Activities," the assumed CNR derivative
instruments are deemed to contain a significant financing element and
all cash flows associated with these positions are reported as
financing activity in the statement of cash flows.
The following details the CNR derivatives (natural gas swaps) we
have assumed:
Open Swap
Avg. Positions
NYMEX as a %
Strike Avg. Fair Assuming of
Price Value Upon Natural Estimated
Open Of Open Acquisition Initial Gas Total
Swaps Swaps of Liability Production Natural
in (per Open Swaps Acquired in Bcf's Gas
Bcf's Mcf) (per Mcf) (per Mcf) of: Production
----------------------------------------------------------------------
Q1 2008 9.5 $4.68 $9.42 ($4.74) 184 5%
Q2 2008 9.5 $4.68 $7.41 ($2.73) 195 5%
Q3 2008 9.7 $4.68 $7.41 ($2.74) 208 5%
Q4 2008 9.7 $4.66 $7.84 ($3.17) 216 4%
======================================================================
Total 2008 38.4 $4.68 $8.02 ($3.34) 803 5%
======================================================================
======================================================================
Total 2009 18.3 $5.18 $7.28 ($2.10) 934 2%
======================================================================
Note: Not shown above are collars covering 3.7 bcf of production
in 2009 at an average floor and ceiling of $4.50 and $6.00.
The company also has the following crude oil swaps in place:
Open Swap Total Total
Positions Losses Lifted
Assuming as a % from Losses per
Open Avg. Oil of Lifted bbl of
Swaps NYMEX Production Estimated Swaps Estimated
in Strike in mbbls Total Oil ($ Total Oil
mbbls Price of: Production millions) Production
----------------------------------------------------------------------
Q1 2008 1,823 73.97 2,675 68% $(3.2) $(1.21)
Q2 2008 1,896 75.58 2,665 71% $(4.7) $(1.77)
Q3 2008 2,039 76.92 2,680 76% $(4.6) $(1.72)
Q4 2008 1,886. 79.01 2,680 70% $(4.7) $(1.77)
======================================================================
Total
2008(1) 7,644 $76.40 10,700 71% $(17.2) $(1.62)
======================================================================
======================================================================
Total
2009(1) 8,395 $82.33 11,000 76% -- --
======================================================================
(1) Certain hedging arrangements include cap-swaps and knockout
swaps with provisions limiting the counterparty's exposure below
prices ranging from $45.00 to $60.00 covering 4,304 mbbls in 2008 and
from $52.50 to $60.00 covering 7,848 mbbls in 2009.
Note: Not shown above are written call options covering 2,564
mbbls of production in 2008 at a weighted average price of $82.50 for
a weighted average premium of $3.17 and 2,555 mbbls of production in
2009 at a weighed average price of $82.14 for a weighted average
premium of $4.98.
CONTACT: Chesapeake Energy Corporation
Jeffrey L. Mobley, CFA, 405-767-4763
Senior Vice President -
Investor Relations and Research
jeff.mobley@chk.com
or
Marc Rowland, 405-879-9232
Executive Vice President
and Chief Financial Officer
marc.rowland@chk.com
SOURCE: Chesapeake Energy Corporation