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Net Income Available to Common Shareholders Reaches $232 Million on Revenue of $1.6 Billion and Production of 154 Bcfe; Adjusted Net Income Available to Common Shareholders Reaches $425 Million Proved Reserves Reach Record Level of 9.4 Tcfe; Company Delivers First Quarter Reserve Replacement Rate of 410% from 475 Bcfe of Additions Company Provides Updated and Detailed Review of its 18.3 Tcfe of Risked Unproved Reserves Located on its 11.2 Million Net Acres of U.S. Onshore LeaseholdOKLAHOMA CITY, May 03, 2007 (BUSINESS WIRE) -- Chesapeake Energy Corporation (NYSE:CHK) today reported strong
financial and operating results for the first quarter of 2007. For the
quarter, Chesapeake generated net income available to common
shareholders of $232 million ($0.50 per fully diluted common share),
operating cash flow of $1.124 billion (defined as cash flow from
operating activities before changes in assets and liabilities) and
ebitda of $924 million (defined as net income before income taxes,
interest expense, and depreciation, depletion and amortization
expense) on revenue of $1.580 billion and production of 154 billion
cubic feet of natural gas equivalent (bcfe).
The company's 2007 first quarter net income available to common
shareholders and ebitda include an unrealized after-tax mark-to-market
loss of $193 million resulting from the company's oil and natural gas
and interest rate hedging programs. This type of item is typically not
included in published estimates of the company's financial results by
certain securities analysts.
Excluding this item, Chesapeake generated adjusted net income to
common shareholders in the 2007 first quarter of $425 million ($0.87
per fully diluted common share) and adjusted ebitda of $1.234 billion.
The excluded item does not affect the calculation of operating cash
flow.
A reconciliation of operating cash flow, ebitda, adjusted ebitda
and adjusted net income to comparable financial measures calculated in
accordance with generally accepted accounting principles is presented
on pages 19 - 20 of this release.
Key Operational and Financial Statistics Summarized Below for the
2007 First Quarter, 2006 Fourth Quarter and 2006 First Quarter
The table below summarizes Chesapeake's key results during the
2007 first quarter and compares them to the 2006 fourth quarter and
the 2006 first quarter.
Three Months Ended:
---------------------------
3/31/07 12/31/06 3/31/06
-------- --------- --------
Average daily production (in mmcfe) 1,707 1,653 1,519
Natural gas as % of total production 92 91 91
Natural gas production (in bcf) 140.8 138.8 124.1
Average realized natural gas price ($/mcf)
(a) 9.26 9.03 9.61
Oil production (in mbbls) 2,143 2,217 2,116
Average realized oil price ($/bbl) (a) 61.13 59.95 57.12
Natural gas equivalent production (in bcfe) 153.7 152.1 136.8
Natural gas equivalent realized price
($/mcfe) (a) 9.33 9.11 9.60
Oil and natural gas marketing income
($/mcfe) .10 .11 .10
Service operations income ($/mcfe) .08 .09 .11
Production expenses ($/mcfe) (.93) (.82) (.87)
Production taxes ($/mcfe) (.27) (.31) (.40)
General and administrative costs ($/mcfe)
(b) (.27) (.22) (.17)
Stock-based compensation ($/mcfe) (.07) (.04) (.05)
DD&A of oil and natural gas properties
($/mcfe) (2.56) (2.51) (2.23)
D&A of other assets ($/mcfe) (.23) (.20) (.17)
Interest expense ($/mcfe) (a) (.50) (.54) (.52)
Operating cash flow ($ in millions) (c) 1,124 1,095 1,047
Operating cash flow ($/mcfe) 7.31 7.20 7.66
Adjusted ebitda ($ in millions) (d) 1,234 1,210 1,147
Adjusted ebitda ($/mcfe) 8.03 7.96 8.39
Net income to common shareholders ($ in
millions) 232 446 604
Earnings per share - assuming dilution ($) 0.50 0.96 1.44
Adjusted net income to common shareholders
($ in millions) (e) 425 418 444
Adjusted earnings per share - assuming
dilution ($) 0.87 0.90 1.07
(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 before income taxes, interest expense,
and depreciation, depletion and amortization expense, as adjusted to
remove the effects of certain items detailed on page 20
(e) defined as net income available to common shareholders, as
adjusted to remove the effects of certain items detailed on page 20
Oil and Natural Gas Production Sets Record for 23rd Consecutive
Quarter; 2007 First Quarter Average Daily Production Increases 12% and
3% Over Production in the 2006 First Quarter and the 2006 Fourth
Quarter
Daily production for the 2007 first quarter averaged 1.707 bcfe,
an increase of 188 million cubic feet of natural gas equivalent
(mmcfe), or 12%, over the 1.519 bcfe of daily production in the 2006
first quarter and an increase of 54 mmcfe, or 3%, over the 1.653 bcfe
produced per day in the 2006 fourth quarter.
Chesapeake's 2007 first quarter production of 153.7 bcfe was
comprised of 140.8 billion cubic feet of natural gas (bcf) (92% on a
natural gas equivalent basis) and 2.14 million barrels of oil and
natural gas liquids (mmbbls) (8% on a natural gas equivalent basis).
Chesapeake's average daily production for the quarter of 1.707 bcfe
consisted of 1.564 bcf of natural gas and 23,811 barrels (bbls) of
oil. The 2007 first quarter was Chesapeake's 23rd consecutive quarter
of sequential U.S. production growth. Over these 23 quarters,
Chesapeake's U.S. production has increased 326%, for an average
compound quarterly growth rate of 6.5% and an average compound annual
growth rate of 29%.
The company's rate of production has recently exceeded 1.8 bcfe
per day and based on projected drilling levels and anticipated
results, Chesapeake is affirming its previous forecasts for total
production growth of 14-18% for 2007 and 10-14% for 2008.
Oil and Natural Gas Proved Reserves Reach Record Level of 9.4
Tcfe; Drilling and Acquisition Costs Average $2.58 per Mcfe as Company
Added 475 Bcfe for a Reserve Replacement Rate of 410%
Chesapeake began 2007 with estimated proved reserves of 8.956
trillion cubic feet of natural gas equivalent (tcfe) and ended the
quarter with 9.431 tcfe, an increase of 475 bcfe, or 5.3%. During the
quarter, Chesapeake replaced its 154 bcfe of production with an
estimated 629 bcfe of new proved reserves for a reserve replacement
rate of 410%. Reserve replacement through the drillbit was 535 bcfe,
or 349% of production (including 205 bcfe of positive performance
revisions and 135 bcfe of positive revisions resulting from oil and
natural gas price increases between December 31, 2006 and March 31,
2007) and 85% of the total increase. Reserve replacement through the
acquisition of proved reserves was 94 bcfe, or 61% of production and
15% of the total increase.
On a per thousand cubic feet of natural gas equivalent (mcfe)
basis, the company's total drilling and acquisition costs were $2.58
per mcfe (excluding costs of $50 million for seismic, $405 million for
unproved properties and leasehold acquired during the quarter and $12
million relating to tax basis step-up and asset retirement
obligations, as well as positive revisions of proved reserves from
higher oil and natural gas prices). Excluding these items described
above, Chesapeake's exploration and development costs through the
drillbit were $2.66 per mcfe during the 2007 first quarter while
reserve replacement costs through acquisitions of proved reserves were
$2.21 per mcfe. Total costs incurred in oil and natural gas
acquisition, exploration and development during the quarter, including
seismic, leasehold, unproved properties, capitalized internal costs,
non-cash tax basis step-up from corporate acquisitions and asset
retirement obligations, were $1.741 billion. A complete reconciliation
of finding and acquisition costs and a roll-forward of proved reserves
are presented on page 17 of this release.
During the 2007 first quarter, Chesapeake continued the industry's
most active drilling program and drilled 476 gross (404 net) operated
wells and participated in another 394 gross (57 net) wells operated by
other companies. The company's drilling success rate was 99% for
company-operated wells and 98% for non-operated wells. Also during the
quarter, Chesapeake invested $906 million in operated wells (using an
average of 129 operated rigs), $160 million in non-operated wells
(using an average of 94 non-operated rigs), $148 million to acquire
new leasehold (exclusive of $258 million in unproved leasehold
obtained through corporate and asset acquisitions) and $50 million to
acquire seismic data.
As of March 31, 2007, Chesapeake's estimated future net cash
flows, discounted at an annual rate of 10% before income taxes (PV-10)
were $20.2 billion using field differential adjusted prices of $60.75
per bbl (based on a NYMEX quarter-end price of $65.85 per bbl) and
$7.01 per thousand cubic feet of natural gas (mcf) (based on a NYMEX
quarter-end price of $7.34 per mcf).
By comparison, the December 31, 2006 PV-10 of the company's proved
reserves was $13.6 billion using field differential adjusted prices of
$56.25 per bbl (based on a NYMEX year-end price of $61.15 per bbl) and
$5.41 per mcf (based on a NYMEX year-end price of $5.64 per mcf).
Additionally, the March 31, 2006 PV-10 of the company's proved
reserves was $17.6 billion using field differential adjusted prices of
$62.06 per bbl (based on a NYMEX year-end price of $66.33 per bbl) and
$6.69 per mcf (based on a NYMEX year-end price of $7.18 per mcf).
Chesapeake's current PV-10 changes by approximately $360 million
for every $0.10 per mcf change in natural gas prices and approximately
$50 million for every $1.00 per bbl change in oil prices. 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 oil and natural
gas 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, the net
book value of the company's other assets (including drilling rigs,
land and buildings, investments in companies, securities, long-term
derivative instruments and other non-current assets) was $2.7 billion
as of March 31, 2007, $2.8 billion as of December 31, 2006 and $1.6
billion as of March 31, 2006.
Average Realized Prices, Hedging Results and Hedging Positions
Detailed
Average prices realized during the 2007 first quarter (including
realized gains or losses from oil and natural gas derivatives, but
excluding unrealized gains or losses on such derivatives) were $61.13
per bbl and $9.26 per mcf, for a realized natural gas equivalent price
of $9.33 per mcfe. Chesapeake's average realized pricing differentials
to NYMEX during the first quarter were a negative $5.36 per bbl and a
negative $0.46 per mcf. Realized gains from oil and natural gas
hedging activities during the quarter generated an $8.33 gain per bbl
and a $2.95 gain per mcf, for a 2007 first quarter realized hedging
gain of $433 million, or $2.82 per mcfe.
The following tables compare Chesapeake's open hedge position
through swaps and collars as well as gains from lifted hedges as of
May 3, 2007 to those previously announced as of February 22, 2007.
Depending on changes in oil and natural gas futures markets and
management's view of underlying oil and natural gas 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 3, 2007
Natural Gas Oil
----------------------- -------------------------
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
==================== ============= ========= ============= ===========
2007 Q2 53% 8.11 77% 71.22
2007 Q3 54% 8.30 77% 71.61
2007 Q4 55% 8.98 77% 71.57
==================== ============= ========= ============= ===========
2007 Q2-Q4 Total 54% 8.49 77% 71.47
==================== ============= ========= ============= ===========
2008 Total 64% 9.20 72% 72.61
==================== ============= ========= ============= ===========
2009 Total 13% 8.87 19% 75.41
==================== ============= ========= ============= ===========
Open Natural Gas Collar Positions as of May 3, 2007
Average Average
Floor Ceiling
Quarter or Year % Hedged $ NYMEX $ NYMEX
================================= ========== ============ ============
2007 Q2 15% 6.76 8.20
2007 Q3 14% 6.76 8.20
2007 Q4 11% 7.13 8.88
================================= ========== ============ ============
2007 Q2-Q4 Total 13% 6.88 8.41
================================= ========== ============ ============
2008 Total 4% 7.41 9.40
================================= ========== ============ ============
2009 Total 2% 7.50 10.72
================================= ========== ============ ============
Gains From Lifted Natural Gas Hedges as of May 3, 2007
Assuming Natural
Total Gain Gas Production of: Gain
Quarter or Year ($ millions) (bcf) ($ per mcf)
========================= ============ =================== ===========
2007 Q2 112 147.5 0.76
2007 Q3 105 158.0 0.67
2007 Q4 117 172.5 0.68
========================= ============ =================== ===========
2007 Q2-Q4 Total 334 478 0.70
========================= ============ =================== ===========
2008 Total 105 701 0.15
========================= ============ =================== ===========
2009 Total 4 750 0.01
========================= ============ =================== ===========
Additionally, the company has lifted a portion of its oil hedges
securing gains of $6.3 million and $4.8 million for the second through
fourth quarters of 2007 and for the full year 2008, respectively.
Open Swap Positions as of February 22, 2007
Natural Gas Oil
------------------- --------------------
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
============================= ========== ======== ========= ==========
2007 Q1 32% 9.71 56% 71.98
2007 Q2 50% 8.06 60% 72.12
2007 Q3 54% 8.23 60% 71.89
2007 Q4 54% 8.95 60% 71.61
============================= ========== ======== ========= ==========
2007 Total 48% 8.63 59% 71.90
============================= ========== ======== ========= ==========
2008 Total 60% 9.20 51% 71.63
============================= ========== ======== ========= ==========
2009 Total 7% 9.00 2% 66.10
============================= ========== ======== ========= ==========
Open Natural Gas Collar Positions as of February 22, 2007
Average Average
Floor Ceiling
Quarter or Year % Hedged $ NYMEX $ NYMEX
================================= ============ ========== ============
2007 Q1 -- -- --
2007 Q2 15% 6.76 8.20
2007 Q3 14% 6.76 8.20
2007 Q4 11% 7.13 8.88
================================= ============ ========== ============
2007 Total 10% 6.88 8.41
================================= ============ ========== ============
2008 Total 3% 7.38 9.20
================================= ============ ========== ============
Gains From Lifted Natural Gas Hedges as of February 22, 2007
Assuming Natural Gas
Total Gain Production of: Gain
Quarter or Year ($ millions) (bcf) ($ per mcf)
======================== ============ ==================== ===========
2007 Q1 281 139.0 2.02
2007 Q2 114 147.5 0.77
2007 Q3 104 159.0 0.65
2007 Q4 116 173.5 0.67
======================== ============ ==================== ===========
2007 Total 615 619 0.99
======================== ============ ==================== ===========
2008 Total 105 701 0.15
======================== ============ ==================== ===========
2009 Total 4 750 0.01
======================== ============ ==================== ===========
Certain open natural gas swap positions include "knockout"
provisions at prices ranging from $5.25 to $6.50 covering 152 bcf in
2007, $5.75 to $6.50 covering 189 bcf in 2008 and $5.90 to $6.25
covering 79 bcf in 2009, and certain open natural gas collar positions
include "knockout" provisions at prices ranging from $5.00 to $6.00
covering 52 bcf in 2007, $5.00 to $6.00 covering 11 bcf in 2008 and
$6.00 covering 18 bcf in 2009. Also, certain open oil swap positions
include "knockout" provisions at prices ranging from $45.00 to $60.00
covering 2.2 mmbbls in 2007, 2.9 mmbbls in 2008 and 1.5 mmbbls in
2009.
The company's updated forecasts for 2007 and 2008 are attached to
this release in an Outlook dated May 3, 2007 labeled as Schedule "A",
which begins on page 21. This Outlook has been changed from the
Outlook dated February 22, 2007 (attached as Schedule "B", which
begins on page 25) to reflect various updated information.
Chesapeake's Leasehold and 3-D Seismic Inventories Now Total 11.2
Million Net Acres and 16.7 Million Acres; Risked Unproved Reserves in
the Company's Inventory Now Reach 18.3 Tcfe, Bringing Total Reserve
Base to 27.7 Tcfe
Since 2000, Chesapeake has invested $7.1 billion in new leasehold
and 3-D seismic acquisitions and now owns one of the largest
inventories of onshore leasehold (11.2 million net acres) and 3-D
seismic (16.7 million acres) in the U.S. On this leasehold, the
company has approximately 26,500 net drilling locations, representing
an approximate 10-year inventory of drilling projects, on which it
believes it can develop an estimated 3.5 tcfe of proved undeveloped
reserves and approximately 18.3 tcfe of risked unproved reserves (73
tcfe of unrisked unproved reserves). Chesapeake's 9.4 tcfe of proved
reserves and its 18.3 tcfe of risked unproved reserves total
approximately 27.7 tcfe.
To aggressively develop these assets, Chesapeake has continued to
significantly strengthen its technical capabilities by increasing its
land, geoscience and engineering staff to nearly 1,100 employees.
Today, the company has over 5,000 employees, of which approximately
60% work in the company's E&P operations and approximately 40% work in
the company's oilfield service operations.
Chesapeake characterizes its drilling activity by one of four play
types: conventional gas resource, unconventional gas resource,
emerging unconventional gas resource and Appalachian Basin 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
summarizes Chesapeake's ownership and activity in each gas resource
play type and highlights notable projects in each play.
Conventional Gas Resource Plays - In its traditional conventional
areas (i.e., portions of the Mid-Continent, Permian, Gulf Coast and
South Texas regions), where exploration targets are typically deep and
defined using 3-D seismic data, Chesapeake believes it has a
meaningful competitive advantage due to its operating scale, deep
drilling expertise and over 13.1 million acres of 3-D seismic data. In
these plays, Chesapeake owns 3.4 million net acres on which it has an
estimated 3.0 tcfe of proved developed reserves, 1.0 tcfe of proved
undeveloped reserves and approximately 3.3 tcfe of risked unproved
reserves and is currently using 28 operated drilling rigs to further
develop its inventory of approximately 3,600 drillsites. Three of
Chesapeake's most important conventional gas resource plays are
described below:
-- Southern Oklahoma (generally Pennsylvanian-aged formations in
Bray, Cement, Golden Trend, Sholem Alechem and Texoma): From
various formations located in the Marietta, Ardmore and
Anadarko Basins, the company is producing approximately 170
mmcfe net per day. The company is currently using nine
operated rigs to further develop its 415,000 net acres of
leasehold. Chesapeake's proved developed reserves in southern
Oklahoma are an estimated 564 bcfe, its proved undeveloped
reserves are an estimated 242 bcfe and its risked unproved
reserves are approximately 900 bcfe after applying a 75% risk
factor and assuming an additional 650 net wells are drilled in
the years ahead. The company's targeted results for vertical
southern Oklahoma wells are $3.5 million to develop 2.2 bcfe
on approximately 120 acre spacing.
-- South Texas: Located primarily in Zapata County, Texas,
Chesapeake's South Texas assets are producing approximately
145 mmcfe net per day. The company is currently using six
operated rigs to further develop its 140,000 net acres of
leasehold. Chesapeake's proved developed reserves in South
Texas are an estimated 315 bcfe, its proved undeveloped
reserves are an estimated 158 bcfe and its risked unproved
reserves are approximately 300 bcfe after applying a 75% risk
factor and assuming an additional 330 net wells are drilled in
the years ahead. The company's targeted results for vertical
South Texas wells are $2.8 million to develop 1.8 bcfe on
approximately 80 acre spacing.
-- Mountain Front (primarily Morrow and Springer formations in
western Oklahoma): From these prolific formations located in
the Anadarko Basin, the company is producing approximately 110
mmcfe net per day. The company is currently using two operated
rigs to further develop its 150,000 net acres of Mountain
Front leasehold. Chesapeake's proved developed reserves in the
Mountain Front area are an estimated 190 bcfe, its proved
undeveloped reserves are an estimated 57 bcfe and its risked
unproved reserves are approximately 250 bcfe after applying a
70% risk factor and assuming an additional 100 net wells are
drilled in the years ahead. The company's targeted results for
vertical Mountain Front wells are $8.0 million to develop 4.0
bcfe on approximately 320 acre spacing.
Unconventional Gas Resource Plays - In its unconventional gas
resource areas, Chesapeake owns 2.7 million net acres on which it has
an estimated 1.9 tcfe of proved developed reserves, 2.0 tcfe of proved
undeveloped reserves and approximately 10.5 tcfe of risked unproved
reserves and is currently using 83 operated drilling rigs to further
develop its inventory of approximately 12,600 net drillsites. Six of
Chesapeake's most important unconventional gas resource plays are
described below:
-- 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
fourth largest producer of natural gas, the most active
driller and the largest leasehold owner in the Tier 1 sweet
spot of Tarrant, Johnson and western Dallas counties.
Chesapeake is producing approximately 200 mmcfe net per day
from the Fort Worth Barnett Shale. The company is currently
using 28 operated rigs to further develop its 200,000 net
acres of leasehold, of which 160,000 net acres are located in
the Tier 1 area. By mid-year, Chesapeake expects to be using
30-35 operated rigs in the play and to be completing, on
average, one new Barnett Shale well every day. Chesapeake's
proved developed reserves in the Fort Worth Barnett Shale are
an estimated 598 bcfe, its proved undeveloped reserves are an
estimated 711 bcfe and its risked unproved reserves are
approximately 3.6 tcfe after applying a 15% risk factor and
assuming an additional 2,500 net wells are drilled in the
years ahead. The company's targeted results for Tier 1
horizontal Fort Worth Barnett Shale wells are $2.5 million to
develop 2.45 bcfe on approximately 60 acre spacing utilizing
wellbores that are generally 3,000' in length and 500' apart.
Chesapeake's targeted results for Tier 2 horizontal Fort Worth
Barnett Shale wells are $2.25 million to develop 1.5 bcfe.
-- Fayetteville Shale (Arkansas): In this region of growing
importance to Chesapeake, the company is the largest leasehold
owner in the play (second largest in the core area of the
play) and is producing approximately 15 mmcfe net per day. As
a result of extensive analysis and successful drilling results
over the last year by Chesapeake and others, the company has
become more confident in the economic merits of the
Fayetteville Shale play and has upgraded the play from its
emerging unconventional gas resource play category. In the
past two months, Chesapeake has increased its drilling
activity levels more than three-fold to ten operated rigs and
will increase its drilling activity level to 12 operated rigs
by mid-year 2007 to further develop its 370,000 net acres of
leasehold in the core area of the play. Chesapeake's proved
developed reserves in the Fayetteville Shale are an estimated
34 bcfe, its proved undeveloped reserves are an estimated 55
bcfe and its risked unproved reserves are approximately 3.0
tcfe after applying a 50% risk factor to its core area acreage
and assuming an additional 2,300 net wells are drilled in the
years ahead. The company's targeted results for horizontal
core area Fayetteville Shale wells are $2.9 million to develop
1.6 bcfe on approximately 80 acre spacing using approximately
3,000' horizontal laterals. The company is currently risking
its 700,000 net acres of non-core area leasehold at 100%.
-- Sahara (primarily Mississippi, Chester, Hunton formations in
Northwest Oklahoma): In this vast play that extends across
five counties in northwestern Oklahoma, Chesapeake is the
largest producer of natural gas, the most active driller and
the largest leasehold owner in the area. Chesapeake is
producing approximately 160 mmcfe net per day in the Sahara
area. The company is currently using 15 operated rigs to
further develop its 680,000 net acres of leasehold.
Chesapeake's proved developed reserves in Sahara are an
estimated 494 bcfe, its proved undeveloped reserves are an
estimated 455 bcfe and its risked unproved reserves are
approximately 2.4 tcfe after applying a 25% risk factor and
assuming an additional 5,900 net wells are drilled in the
years ahead. The company's targeted results for vertical
Sahara wells are $0.9 million to develop 0.6 bcfe on
approximately 70 acre spacing.
-- Deep Haley (primarily Strawn, Atoka, Morrow formations in West
Texas): In this West Texas Delaware Basin area, Chesapeake is
the second largest leasehold owner and the second most active
driller. The company has also upgraded this play out of its
emerging unconventional gas resource category following recent
favorable drilling results that have increased the company's
production from the Deep Haley area more than 50% over the
last three months to approximately 50 mmcfe net per day. The
company is currently using seven operated rigs to further
develop its 260,000 net acres of leasehold. Chesapeake's
proved developed reserves in Deep Haley are an estimated 61
bcfe, its proved undeveloped reserves are an estimated 60 bcfe
and its risked unproved reserves are approximately 800 bcfe
after applying a 75% risk factor and assuming an additional
200 net wells are drilled in the years ahead. The company's
targeted results for vertical Deep Haley wells are $12.0
million to develop 6.0 bcfe on approximately 320 acre spacing.
-- Ark-La-Tex Tight Gas Sands (primarily Travis Peak, Cotton
Valley, Pettit and Bossier formations): In this large region
covering most of East Texas and northern Louisiana, Chesapeake
has assembled a strong portfolio of unconventional gas
resource plays. Chesapeake is one of the ten largest producers
of natural gas, the third most active driller and one of the
largest leasehold owners in the area. Chesapeake is producing
approximately 130 mmcfe net per day in the Ark-La-Tex area.
The company is currently using 14 operated rigs to further
develop its 200,000 net acres of leasehold. Chesapeake's
unconventional proved developed reserves in the Ark-La-Tex
region are an estimated 365 bcfe, its proved undeveloped
reserves are an estimated 310 bcfe and its unconventional
risked unproved reserves are approximately 250 bcfe after
applying a 70% risk factor and assuming an additional 750 net
wells are drilled in the years ahead. The company's targeted
results for medium-depth vertical Ark-La-Tex wells are $1.7
million to develop 1.0 bcfe on approximately 60 acre spacing.
-- Granite, Atoka and Colony Washes (western Oklahoma and Texas
Panhandle): Chesapeake is the largest producer of natural gas,
the most active driller and the largest leasehold owner in the
various Wash plays of the Anadarko Basin. Chesapeake is
producing approximately 105 mmcfe net per day from these
plays. The company is currently using eight operated rigs to
further develop its 150,000 net acres of leasehold.
Chesapeake's proved developed reserves in the Wash plays are
an estimated 298 bcfe, its proved undeveloped reserves in the
Wash plays are an estimated 418 bcfe and its risked unproved
reserves are approximately 400 bcfe after applying a 50% risk
factor and assuming an additional 700 net wells are drilled in
the years ahead. The company's targeted results for vertical
Wash wells are $2.8 million to develop 1.4 bcfe on
approximately 80 acre spacing.
Emerging Unconventional Gas Resource Plays - In its emerging
unconventional gas resource areas where commercial production has only
recently been established but the future reserve potential could be
substantial, Chesapeake owns 1.5 million net acres on which it has an
estimated 20 bcfe of proved developed reserves, 20 bcfe of proved
undeveloped reserves and approximately 2.0 tcfe of risked unproved
reserves and is currently using eight operated drilling rigs to
further develop its inventory of approximately 900 net drillsites.
Three of Chesapeake's most important emerging unconventional gas
resource plays are described below:
-- Delaware Basin Shales (primarily Barnett and Woodford
formations in West Texas): Chesapeake's most significant land
acquisition activities during 2006 took place in the Delaware
Basin Barnett and Woodford Shale plays in far West Texas where
Chesapeake is now the largest leasehold owner. The company is
producing approximately 1 mmcfe net per day from the Delaware
Basin Barnett and Woodford Shales. The company is currently
using four operated rigs to further develop its 680,000 net
acres of leasehold. Chesapeake's proved developed reserves in
the Delaware Basin shales are an estimated 1 bcfe and it has
not yet booked any proved undeveloped reserves, although its
risked unproved reserves are an estimated 1.0 tcfe after
applying a 90% risk factor and assuming an additional 425 net
wells are drilled in the years ahead. The company's targeted
results for Delaware Basin vertical Barnett and Woodford Shale
wells are $4.5 million to develop 3.0 bcfe on approximately
160 acre spacing. The company has not yet developed a model
for targeted results from horizontal wells in the play.
-- Woodford Shale (southeastern Oklahoma Arkoma Basin):
Chesapeake is the second largest leasehold owner in the
Woodford Shale play, an unconventional gas play in the
southeastern Oklahoma portion of the Arkoma Basin. The company
is producing approximately 10 mmcfe net per day from the
Woodford Shale. The company is currently using three operated
rigs to further develop its 100,000 net acres of leasehold.
Chesapeake's proved developed reserves in the Woodford Shale
are an estimated 17 bcfe, its proved undeveloped reserves in
the play are an estimated 17 bcfe and its risked unproved
reserves are approximately 500 bcfe after applying a 50% risk
factor and assuming an additional 300 net wells are drilled in
the years ahead. The company's targeted results for horizontal
Woodford Shale wells are $4.3 million to develop 2.2 bcfe on
approximately 160 acre spacing.
-- Deep Bossier (East Texas and northern Louisiana): Chesapeake
is one of the top three leasehold owners in the Deep Bossier
play. The company is producing approximately 3 mmcfe net per
day in the Deep Bossier play. The company is currently using
one operated rig and plans to increase its operated rig count
to six rigs by year-end 2007 to further develop its 350,000
net acres of leasehold. Chesapeake's proved developed reserves
in the Deep Bossier are an estimated 3 bcfe, its proved
undeveloped reserves are an estimated 3 bcfe and its risked
unproved reserves are approximately 400 bcfe after applying a
90% risk factor and assuming an additional 100 net wells are
drilled in the years ahead. The company's targeted results for
vertical Deep Bossier wells are $10.0 million to develop 5.0
bcfe on approximately 320 acre spacing.
Appalachian Basin Gas Resource Plays - Chesapeake's Appalachia
play types include conventional, unconventional and emerging
unconventional in the Devonian Shale and other formations. Chesapeake
is the largest leasehold owner in the region with 3.6 million net
acres and is producing approximately 133 mmcfe net per day. The
company is currently using a range of 7-12 operated rigs to further
develop its extensive leasehold position. In Appalachia, Chesapeake
has an estimated 978 bcfe of proved developed reserves, an estimated
528 bcfe of proved undeveloped reserves and its risked unproved
reserves are approximately 2.5 tcfe after applying a 35% risk factor
and assuming an additional 9,300 net wells are drilled in the years
ahead. The company's targeted results for vertical Devonian Shale
wells are $0.5 million to develop 0.35 bcfe on approximately 160 acre
spacing.
In addition, Chesapeake continues to actively generate new
prospects and acquire additional leasehold throughout the company's
areas of operation in various conventional, unconventional and
emerging unconventional plays not described above.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief Executive Officer,
commented, "We are pleased to report outstanding financial and
operational results for the 2007 first quarter. The company delivered
attractive production and reserve growth and generated impressive
profit margins that were enhanced by the company's well-executed
hedging strategy. Our focused business strategy, value-added growth,
tremendous inventory of undrilled locations and valuable hedge
positions clearly differentiate Chesapeake in the industry.
We are pleased to again be recognized by Fortune this year as one
the fastest growing and most profitable companies among the country's
500 largest corporations. In the magazine's recent Fortune 500 survey,
we were ranked #325 by revenues (up from #451 last year - the third
largest ranking increase in the survey), #96 by net income, #25 by
earnings per share growth over the last ten years and #14 by profits
as a percentage of revenues. Additionally, Chesapeake was recognized
in this year's Forbes Global 2000 listing as one of the 500 largest
companies in the world based on sales, profits, assets and market
value.
We look forward to another successful year in 2007 as our shift in
focus from resource inventory capture to resource inventory conversion
continues to generate impressive results and create substantial
shareholder value. Through the industry's most active drilling
program, we plan to increase our average daily production rate by
14-18% in 2007 and we expect to exceed 10 tcfe of proved reserves by
year-end 2007. The Fort Worth Barnett Shale play will be the largest
contributor to the company's 2007 success and we are also pleased with
our recent progress in the Fayetteville Shale and Deep Haley plays.
Furthermore, the combination of attractive natural gas prices with
decreasing oilfield service costs may well make 2007 a golden year of
value creation for Chesapeake and the E&P industry.
Looking forward, we believe that Chesapeake is well positioned to
prosper for years to come. As the debate in America intensifies about
how to become more energy independent in an increasingly dangerous
world and at the same time reduce greenhouse gas emissions in a
growing economy, natural gas is emerging as the most practical
solution to the challenge at hand. The vast majority of greenhouse gas
emissions are caused by transportation vehicles burning gasoline and
diesel and by power plants and factories burning coal. Today, we see
policymakers promoting alternative fuels such as wind, solar, biofuels
and nuclear. These are all legitimate alternatives (although some much
less so than others), yet none can offer energy in great abundance at
a reasonable price anytime soon. However, burning natural gas instead
of gasoline, diesel or coal reduces greenhouse gas emissions by
approximately 50%. We believe the evidence clearly demonstrates that
natural gas is by far the most practical solution to the problem - it
is abundant, affordable, reliable, clean burning and domestically
produced.
For many years, natural gas has been valued at a BTU discount to
oil. We believe the opportunity is now at hand for the climate change
debate to lead to an increased appreciation of natural gas and a
higher valuation for the superior fuel we produce. We intend to do
well for our shareholders by doing well for our country and our
world."
Conference Call Information
A conference call to discuss this release has been scheduled for
Friday morning, May 4, 2007 at 9:00 a.m. EDT. The telephone number to
access the conference call is 913-981-4911 and the confirmation code
is 9507142. We encourage those who would like to participate in the
call to dial the access number between 8:50 and 8:55 a.m. EDT. For
those unable to participate in the conference call, a replay will be
available for audio playback from noon EDT, May 4, 2007 through
midnight EDT on May 18, 2007. The number to access the conference call
replay is 719-457-0820 and the passcode for the replay is 9507142. The
conference call will also be webcast live on the Internet and can be
accessed by going to Chesapeake's website at www.chkenergy.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 oil and natural
gas reserves, expected oil and natural gas production and future
expenses, projections of future oil and natural gas prices, planned
capital expenditures for drilling, leasehold acquisitions and seismic
data, and 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 under "Risk Factors" in Item 1A of our
2006 annual report on Form 10-K filed with the Securities and Exchange
Commission on March 1, 2007. They include the volatility of oil and
natural gas prices; the limitations our level of indebtedness may have
on our financial flexibility; our ability to compete effectively
against strong independent oil and natural gas companies and majors;
the availability of capital on an economic basis to fund reserve
replacement costs; our ability to replace reserves and sustain
production; uncertainties inherent in estimating quantities of oil and
natural gas reserves and projecting future rates of production and the
timing of development expenditures; uncertainties in evaluating oil
and natural gas 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 oil and
natural gas properties resulting in ceiling test write-downs; lower
prices realized on oil and natural gas sales and collateral required
to secure hedging liabilities resulting from our commodity price risk
management activities; the negative impact lower oil and natural gas
prices could have on our ability to borrow; drilling and operating
risks; 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 oil and natural gas 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 independent and
sixth largest overall 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 Mid-Continent, Fort Worth Barnett Shale,
Fayetteville Shale, Permian Basin, Delaware Basin, South Texas, Texas
Gulf Coast, Ark-La-Tex and Appalachian Basin regions of the United
States. The company's Internet address is www.chkenergy.com.
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
March 31, March 31,
THREE MONTHS ENDED: 2007 2006
---------------------------------- ----------------- -----------------
$ $/mcfe $ $/mcfe
---------- ------ ---------- ------
REVENUES:
Oil and natural gas sales 1,124,518 7.31 1,510,821 11.05
Oil and natural gas marketing
sales 421,914 2.75 404,367 2.96
Service operations revenue 33,408 0.22 29,379 0.21
---------- ------ ---------- ------
Total Revenues 1,579,840 10.28 1,944,567 14.22
---------- ------ ---------- ------
OPERATING COSTS:
Production expenses 142,271 0.93 119,392 0.87
Production taxes 41,891 0.27 55,373 0.40
General and administrative
expenses 52,397 0.34 28,791 0.21
Oil and natural gas marketing
expenses 406,758 2.65 391,360 2.87
Service operations expense 21,657 0.14 14,437 0.11
Oil and natural gas
depreciation, depletion and
amortization 393,331 2.56 304,957 2.23
Depreciation and amortization of
other assets 35,900 0.23 23,872 0.17
Employee retirement expense -- -- 54,753 0.40
---------- ------ ---------- ------
Total Operating Costs 1,094,205 7.12 992,935 7.26
---------- ------ ---------- ------
INCOME FROM OPERATIONS 485,635 3.16 951,632 6.96
---------- ------ ---------- ------
OTHER INCOME (EXPENSE):
Interest and other income 9,215 0.06 9,636 0.07
Interest expense (78,738) (0.51) (72,658) (0.53)
Gain on sale of investment -- -- 117,396 0.86
---------- ------ ---------- ------
Total Other Income
(Expense) (69,523) (0.45) 54,374 0.40
---------- ------ ---------- ------
INCOME BEFORE INCOME TAXES 416,112 2.71 1,006,006 7.36
---------- ------ ---------- ------
Income Tax Expense:
Current -- -- -- --
Deferred 158,123 1.03 382,283 2.80
---------- ------ ---------- ------
Total Income Tax Expense 158,123 1.03 382,283 2.80
---------- ------ ---------- ------
NET INCOME 257,989 1.68 623,723 4.56
Preferred stock dividends (25,836) (0.17) (18,812) (0.13)
Loss on exchange/conversion of
preferred stock -- -- (1,009) (0.01)
---------- ------ ---------- ------
NET INCOME AVAILABLE TO COMMON
SHAREHOLDERS 232,153 1.51 603,902 4.42
========== ====== ========== ======
EARNINGS PER COMMON SHARE:
Basic $0.51 $1.64
========== ==========
Assuming dilution $0.50 $1.44
========== ==========
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in
000's)
Basic 451,349 368,625
========== ==========
Assuming dilution 516,391 431,455
========== ==========
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in 000's)
(unaudited)
March 31, December 31,
2007 2006
-------------------------------------------- ------------ ------------
Cash $3,576 $2,519
Other current assets 1,219,084 1,151,350
------------ ------------
Total Current Assets 1,222,660 1,153,869
------------ ------------
Property and equipment (net) 23,397,849 21,904,043
Other assets 1,111,833 1,359,255
------------ ------------
Total Assets $25,732,342 $24,417,167
============ ============
Current liabilities $2,179,921 $1,889,809
Long-term debt, net 8,371,323 7,375,548
Asset retirement obligation 201,000 192,772
Other long-term liabilities 529,755 390,108
Deferred tax liability 3,373,314 3,317,459
------------ ------------
Total Liabilities 14,655,313 13,165,696
Stockholders' Equity 11,077,029 11,251,471
------------ ------------
Total Liabilities & Stockholders' Equity $25,732,342 $24,417,167
============ ============
Common Shares Outstanding 460,479 457,434
============ ============
CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
(in 000's)
(unaudited)
% of Total % of Total
March 31, Book December 31, Book
2007 Capitalization 2006 Capitalization
-------------- ------------ -------------- ------------ --------------
Long-term
debt, net $8,371,323 43% $7,375,548 40%
Stockholders'
equity 11,077,029 57% 11,251,471 60%
------------ -------------- ------------ --------------
Total $19,448,352 100% $18,627,019 100%
============ ============== ============ ==============
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2007 ADDITIONS TO OIL AND NATURAL GAS PROPERTIES
($ in 000's, except per unit amounts)
(unaudited)
Reserves
Cost (in mmcfe) $/mcfe
---------------------------------- ------------ ----------- -------
Exploration and development costs $1,066,277 400,680 (a) $2.66
Acquisition of proved properties 207,585 93,726 $2.21
------------ -----------
Subtotal 1,273,862 494,406 $2.58
Divestitures (208) (1)
Geological and geophysical costs 50,371 --
------------ -----------
Adjusted subtotal 1,324,025 494,405 $2.68
Revisions - price -- 135,120
Acquisition of unproved properties 257,835 --
Leasehold acquisition costs 147,519 --
------------ -----------
Adjusted subtotal 1,729,379 629,525 $2.75
Tax basis step-up 7,186 --
Asset retirement obligation 4,815 --
------------ -----------
Total $1,741,380 629,525 $2.77
============ ===========
(a) Includes positive performance revisions of 205 bcfe and
excludes upward revisions of 135 bcfe resulting from oil and natural
gas price increases between December 31, 2006 and March 31, 2007.
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
THREE MONTHS ENDED MARCH 31, 2007
(unaudited)
Mmcfe
----------------------------------------------------------- ----------
Beginning balance, 01/01/07 8,955,614
Extensions and discoveries 196,117
Acquisitions 93,726
Revisions - performance 204,563
Revisions - price 135,120
Production (153,650)
Divestitures (1)
----------
Ending balance, 03/31/07 9,431,489
==========
Reserve replacement 629,525
Reserve replacement ratio (a) 410%
(a) The company uses the reserve replacement ratio as an indicator
of the company's ability to replenish annual production volumes and
grow its reserves, thereby providing some information on the sources
of future production. It should be noted that the reserve replacement
ratio is a statistical indicator that has limitations. The ratio is
limited because it typically varies widely based on the extent and
timing of new discoveries and property acquisitions. Its predictive
and comparative value is also limited for the same reasons. In
addition, since the ratio does not imbed the cost or timing of future
production of new reserves, it cannot be used as a measure of value
creation.
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL AND NATURAL GAS SALES AND INTEREST EXPENSE
(unaudited)
March 31, March 31,
THREE MONTHS ENDED: 2007 2006
---------------------------------------------- ----------- -----------
Oil and Natural Gas Sales ($ in thousands):
Oil sales $113,153 $124,667
Oil derivatives - realized gains (losses) 17,848 (3,808)
Oil derivatives - unrealized gains (losses) (12,057) (1,335)
----------- -----------
Total Oil Sales 118,944 119,524
----------- -----------
Natural gas sales 887,989 940,318
Natural gas derivatives - realized gains
(losses) 415,072 252,029
Natural gas derivatives - unrealized gains
(losses) (297,487) 198,950
----------- -----------
Total Natural Gas Sales 1,005,574 1,391,297
----------- -----------
Total Oil and Natural Gas Sales $1,124,518 $1,510,821
=========== ===========
Average Sales Price (excluding gains (losses)
on derivatives):
Oil ($ per bbl) $52.80 $58.92
Natural gas ($ per mcf) $6.31 $7.58
Natural gas equivalent ($ per mcfe) $6.52 $7.79
Average Sales Price (excluding unrealized
gains (losses) on derivatives):
Oil ($ per bbl) $61.13 $57.12
Natural gas ($ per mcf) $9.26 $9.61
Natural gas equivalent ($ per mcfe) $9.33 $9.60
Interest Expense ($ in thousands)
Interest $76,076 $72,898
Derivatives - realized (gains) losses 1,496 (1,244)
Derivatives - unrealized (gains) losses 1,166 1,004
----------- -----------
Total Interest Expense $78,738 $72,658
=========== ===========
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
(in 000's)
(unaudited)
March 31, March 31,
THREE MONTHS ENDED: 2007 2006
---------------------------------------------- ----------- -----------
Beginning cash $2,519 $60,027
Cash provided by operating activities 976,532 967,458
Cash (used in) investing activities (1,869,131) (1,960,061)
Cash provided by financing activities 893,656 970,862
----------- -----------
Ending cash $3,576 $38,286
=========== ===========
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
(in 000's)
(unaudited)
March 31, December 31, March 31,
THREE MONTHS ENDED: 2007 2006 2006
-------------------------------- ----------- ------------- -----------
CASH PROVIDED BY OPERATING
ACTIVITIES $976,532 $1,861,055 $967,458
Adjustments:
Changes in assets and
liabilities 146,979 (765,578) 79,405
----------- ------------- -----------
OPERATING CASH FLOW(a) $1,123,511 $1,095,477 $1,046,863
=========== ============= ===========
(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 an oil and
natural gas 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 oil and natural gas 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: 2007 2006 2006
--------------------------------- --------- -------------- -----------
NET INCOME $257,989 $471,362 $623,723
Income tax expense 158,123 288,900 382,283
Interest expense 78,738 80,496 72,658
Depreciation and amortization of
other assets 35,900 30,189 23,872
Oil and natural gas depreciation,
depletion and amortization 393,331 381,680 304,957
--------- -------------- -----------
EBITDA(b) $924,081 $1,252,627 $1,407,493
========= ============== ===========
(b) Ebitda represents net income 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: 2007 2006 2006
----------------------------- ------------ --------------- -----------
CASH PROVIDED BY OPERATING
ACTIVITIES $976,532 $1,861,055 $967,458
Changes in assets and
liabilities 146,979 (765,578) 79,405
Interest expense 78,738 80,496 72,658
Unrealized gains on oil and
natural gas derivatives (309,544) 42,905 197,615
Other non-cash items 31,376 33,749 90,357
------------ --------------- -----------
EBITDA $924,081 $1,252,627 $1,407,493
============ =============== ===========
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
($ in 000's, except per share amounts)
(unaudited)
March 31, December 31, March 31,
THREE MONTHS ENDED: 2007 2006 2006
----------------------------------- ---------- ------------- ---------
Net income available to common
shareholders $232,153 $445,510 $603,902
Adjustments:
Unrealized (gains) losses on
derivatives, net of tax 192,640 (27,142) (121,899)
Loss on conversion/exchange of
preferred stock -- -- 1,009
Employee retirement expense, net
of tax -- -- 33,947
Gain on sale of investment, net
of tax -- -- (72,786)
---------- ------------- ---------
Adjusted net income available to
common shareholders(1) 424,793 418,368 444,173
Preferred dividends 25,836 25,852 18,812
---------- ------------- ---------
Total adjusted net income $450,629 $444,220 $462,985
========== ============= =========
Weighted average fully diluted
shares outstanding(2) 516,391 491,000 431,723
Adjusted earnings per share
assuming dilution $0.87 $0.90 $1.07
========== ============= =========
(1) Adjusted net income available to common and adjusted earnings
per share assuming dilution exclude certain items that management
believes affect the comparability of operating results. The company
discloses these non-GAAP financial measures as a useful adjunct to
GAAP earnings because:
a. Management uses adjusted net income available to common to
evaluate the company's operational trends and performance relative to
other oil and natural gas producing companies.
b. Adjusted net income available to common is more comparable to
earnings estimates provided by securities analysts.
c. Items excluded generally are one-time items, or items whose
timing or amount cannot be reasonably estimated. Accordingly, any
guidance provided by the company generally excludes information
regarding these types of items.
(2) Weighted average fully diluted shares outstanding includes
shares that were considered antidilutive for calculating earnings per
share in accordance with GAAP.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in 000's)
(unaudited)
March 31, December 31, March 31,
THREE MONTHS ENDED: 2007 2006 2006
------------------------------- ----------- -------------- -----------
EBITDA $924,081 $1,252,627 $1,407,493
Adjustments, before tax:
Unrealized (gains) losses on
oil and natural gas
derivatives 309,544 (42,905) (197,615)
Employee retirement expense -- -- 54,753
Gain on sale of investment -- -- (117,396)
----------- -------------- -----------
Adjusted ebitda(1) $1,233,625 $1,209,722 $1,147,235
=========== ============== ===========
(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 oil and natural
gas 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 3, 2007
Quarter Ending June 30, 2007; Year Ending December 31, 2007; and
Year Ending December 31, 2008.
We have adopted a policy of periodically providing investors with
guidance on certain factors that affect our future financial
performance. As of May 3, 2007, we are using the following key
assumptions in our projections for the second quarter of 2007, the
full-year 2007 and the full-year 2008.
The primary changes from our February 22, 2007 Outlook are in
italicized bold in the table and are explained as follows:
1) We have provided our first guidance for the quarter ending June
30, 2007;
2) We have updated the projected effect of changes in our hedging
positions; and
3) Production, certain costs and capital expenditure assumptions
have been updated.
Quarter Ending Year Ending Year Ending
6/30/2007 12/31/2007 12/31/2008
-------------- --------------- --------------
Estimated Production
Oil - mbbls 2,100 8,500 8,500
Natural gas - bcf 145.5 - 149.5 614 - 624 696 - 706
Natural gas equivalent
- bcfe 158 - 162 665 - 675 747 - 757
Daily natural gas
equivalent midpoint -
in mmcfe 1,758 1,836 2,055
NYMEX Prices (a) (for
calculation of realized
hedging effects only):
Oil - $/bbl $56.25 $56.73 $56.25
Natural gas - $/mcf $7.52 $7.32 $7.50
Estimated Realized
Hedging Effects (based
on assumed NYMEX prices
above):
Oil - $/bbl $12.08 $11.28 $12.43
Natural gas - $/mcf $1.23 $1.78 $1.43
Estimated Differentials
to NYMEX Prices:
Oil - $/bbl 6 - 8% 6 - 8% 6 - 8%
Natural gas - $/mcf 8 - 12% 9 - 13% 9 - 13%
Operating Costs per Mcfe
of Projected
Production:
Production expense $0.90 - 1.00 $0.90 - 1.00 $0.90 - 1.00
Production taxes
(generally 6.0% of
O&G revenues) (b) $0.41 - 0.46 $0.41 - 0.46 $0.41 - 0.46
General and
administrative $0.25 - 0.30 $0.25 - 0.30 $0.25 - 0.30
Stock-based
compensation (non-
cash) $0.08 - 0.10 $0.08 - 0.10 $0.10 - 0.12
DD&A of oil and
natural gas assets $2.54 - 2.60 $2.40 - 2.60 $2.50 - 2.70
Depreciation of other
assets $0.24 - 0.28 $0.24 - 0.28 $0.28 - 0.32
Interest expense(c) $0.55 - 0.60 $0.60 - 0.65 $0.60 - 0.65
Other Income per Mcfe:
Oil and natural gas
marketing income $0.06 - 0.08 $0.06 - 0.08 $0.06 - 0.08
Service operations
income $0.08 - 0.12 $0.08 - 0.12 $0.08 - 0.12
Book Tax Rate (About
Equals 95% deferred) 38% 38% 38%
Equivalent Shares
Outstanding - in
millions:
Basic 452 453 458
Diluted 517 519 524
Capital Expenditures -
in millions:
Drilling, leasehold
and seismic $1,200 -1,300 $5,000 - 5,200 $5,000 -5,200
(a) Oil NYMEX prices have been updated for actual contract prices
through March 2007 and natural gas NYMEX prices have been updated for
actual contract prices through April 2007.
(b) Severance tax per mcfe is based on NYMEX prices of $56.25 per
bbl of oil and $7.40 to $8.40 per mcf of natural gas during Q2 2007,
$56.73 per bbl of oil and $7.40 to $8.40 per mcf of natural gas during
calendar 2007 and $56.25 per bbl of oil and $7.50 to $8.50 per mcf of
natural gas during calendar 2008.
(c) 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, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, 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) Basis protection swaps are arrangements that guarantee a
price differential of oil or natural gas from a specified delivery
point. 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.
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 non-qualifying 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:
Total
Open Swap Lifted
Positions Total Gain per
Avg. Assuming as a % of Gains Mcf of
NYMEX Natural Estimated from Estimated
Open Strike 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
======== ====== ======= =========== =========== ========== ===========
2007:
--------
Q2 67.2 $8.05 147.5 46% $111.5 $0.76
Q3 74.9 $8.28 158.0 47% $105.4 $0.67
Q4 84.5 $8.99 172.5 49% $116.8 $0.68
======== ====== ======= =========== =========== ========== ===========
Q2-Q4
2007(1) 226.6 $8.48 478.0 47% $333.7 $0.70
======== ====== ======= =========== =========== ========== ===========
======== ====== ======= =========== =========== ========== ===========
Total
2008(1) 408.7 $9.31 701.0 58% $105.0 $0.15
======== ====== ======= =========== =========== ========== ===========
======== ====== ======= =========== =========== ========== ===========
Total
2009(1) 79.4 $9.21 750.0 11% $3.9 $0.01
======== ====== ======= =========== =========== ========== ===========
(1) Certain hedging arrangements include swaps with knockout
prices ranging from $5.25 to $6.50 covering 152 bcf in Q2-Q4 2007,
$5.75 to $6.50 covering 189 bcf in 2008 and $5.90 to $6.25 covering 79
bcf in 2009.
The company currently has the following open natural gas collars
in place:
Open Swap
Positions
Assuming as a % of
Natural Estimated
Avg. Gas Total
Avg. NYMEX NYMEX Production Natural
Open Swaps Floor Ceiling in Bcf's Gas
in Bcf's Price Price of: Production
=============== ========== ========== ======== =========== ===========
2007:
---------------
Q2 21.8 $6.76 $8.20 147.5 15%
Q3 22.1 $6.76 $8.20 158.0 14%
Q4 19.6 $7.13 $8.88 172.5 11%
=============== ========== ========== ======== =========== ===========
Q2-Q4 2007(1) 63.5 $6.88 $8.41 478.0 13%
=============== ========== ========== ======== =========== ===========
=============== ========== ========== ======== =========== ===========
Total 2008(1) 26.8 $7.41 $9.40 701.0 4%
=============== ========== ========== ======== =========== ===========
=============== ========== ========== ======== =========== ===========
Total 2009(1) 18.3 $7.50 $10.72 750.0 2%
=============== ========== ========== ======== =========== ===========
(1) Certain collar arrangements include knockout prices ranging
from $5.00 to $6.00 covering 52 bcf in Q2-Q4 2007, $5.00 to $6.00
covering 11 bcf in 2008 and $6.00 covering 18 bcf in 2009.
Note: Not shown above are written call options covering 63.3 bcf
of production in Q2-Q4 2007 at a weighted average price of $9.48 for a
weighted average premium of $0.54, 104.0 bcf of production in 2008 at
a weighed average price of $10.39 for a weighted average premium of
$0.68 and 53.8 bcf of production in 2009 at a weighed average price of
$11.51 for a weighted average premium of $0.50.
The company has the following natural gas basis protection swaps
in place:
Mid-Continent Appalachia
------------------------- ---------------------------
Volume in NYMEX Volume in NYMEX
Bcf's less(1): Bcf's plus(1):
----------- ------------- ------------- -------------
Q2-Q4 2007 136.4 0.44 27.5 0.35
2008 118.6 0.27 36.6 0.35
2009 86.6 0.29 25.6 0.31
----------- ------------- ------------- -------------
Totals 341.6 $0.35 89.7 $0.34
=========== ============= ============= =============
(1) 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 ($293 million as of March 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:
Avg. Open Swap
NYMEX Positions
Strike Avg. Fair Assuming as a % of
Price Value Upon Natural Estimated
Open Of Open Acquisition Initial Gas Total
Swaps Swaps of Open Liability Production Natural
in (per Swaps Acquired in Bcf's Gas
Bcf's Mcf) (per Mcf) (per Mcf) of: Production
-------- ------ ------- ------------ --------- ----------- -----------
2007:
Q2 10.5 $4.82 $8.48 ($3.66) 147.5 7%
Q3 10.6 $4.82 $8.45 ($3.63) 158.0 7%
Q4 10.6 $4.82 $8.87 ($4.05) 172.5 6%
======== ====== ======= ============ ========= =========== ===========
Q2-Q4
2007 31.7 $4.82 $8.60 ($3.78) 478.0 7%
======== ====== ======= ============ ========= =========== ===========
======== ====== ======= ============ ========= =========== ===========
Total
2008 38.4 $4.68 $8.02 ($3.34) 701.0 5%
======== ====== ======= ============ ========= =========== ===========
======== ====== ======= ============ ========= =========== ===========
Total
2009 18.3 $5.18 $7.28 ($2.10) 750.0 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 $6.00.
The company also has the following crude oil swaps in place:
Open Swap Total Total
Positions Gains Lifted
Assuming as a % from Gain per
Open Avg. Oil of Lifted bbl of
Swaps NYMEX Production Estimated Swaps Estimated
in Strike in mbbls Total Oil ($ Total Oil
mbbls Price of: Production millions) Production
--------- ------ ------- ---------- ----------- ---------- -----------
2007:
Q2 1,638 $71.22 2,140 77% $2.1 $0.98
Q3 1,656 $71.61 2,140 77% $2.1 $0.99
Q4 1,656 $71.57 2,145 77% $2.1 $0.98
========= ====== ======= ========== =========== ========== ===========
Q2-Q4
2007(1) 4,950 $71.47 6,425 77% $6.3 $0.98
========= ====== ======= ========== =========== ========== ===========
========= ====== ======= ========== =========== ========== ===========
Total
2008(1) 6,130 $72.61 8,500 72% $4.8 $0.57
========= ====== ======= ========== =========== ========== ===========
========= ====== ======= ========== =========== ========== ===========
Total
2009(1) 1,643 $75.41 8,500 19% -- --
========= ====== ======= ========== =========== ========== ===========
(1) Certain hedging arrangements include swaps with knockout
prices ranging from $45.00 to $60.00 covering 2,200 mbbls in Q2-Q4
2007, 2,928 mbbls in 2008 and 1,460 mbbls in 2009.
Note: Not shown above are written call options covering 732 mbbls
of production in 2008 at a weighted average price of $75.00 for a
weighted average premium of $4.90 and 730 mbbls of production in 2009
at a weighed average price of $75.00 for a weighted average premium of
$5.90.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF FEBRUARY 22, 2007
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF MAY 3, 2007
Quarter Ending March 31, 2007; Year Ending December 31, 2007; and
Year Ending December 31, 2008.
We have adopted a policy of periodically providing investors with
guidance on certain factors that affect our future financial
performance. As of February 22, 2007, we are using the following key
assumptions in our projections for the first quarter of 2007, the
full-year 2007 and the full-year 2008.
The primary changes from our December 11, 2006 Outlook are in
italicized bold in the table and are explained as follows:
1) We have updated the projected effect of changes in our hedging
positions; and
2) Production, certain costs and capital expenditure assumptions
have been updated.
Quarter Ending Year Ending Year Ending
3/31/2007 12/31/2007 12/31/2008
-------------- --------------- --------------
Estimated Production
Oil - mbbls 2,100 8,500 8,500
Natural gas - bcf 138 - 140 614 - 624 696 - 706
Natural gas equivalent
- bcfe 150.5 - 152.5 665 - 675 747 - 757
Daily natural gas
equivalent midpoint -
in mmcfe 1,683 1,836 2,055
NYMEX Prices (a) (for
calculation of realized
hedging effects only):
Oil - $/bbl $55.62 $56.09 $56.25
Natural gas - $/mcf $6.76 $7.32 $7.50
Estimated Realized
Hedging Effects (based
on assumed NYMEX prices
above):
Oil - $/bbl $9.82 $9.88 $8.00
Natural gas - $/mcf $3.05 $1.77 $1.35
Estimated Differentials
to NYMEX Prices:
Oil - $/bbl 6 - 8% 6 - 8% 6 - 8%
Natural gas - $/mcf 8 - 12% 9 - 13% 9 - 13%
Operating Costs per Mcfe
of Projected
Production:
Production expense $0.85 - 0.95 $0.90 - 1.00 $0.90 - 1.00
Production taxes
(generally 6.0% of
O&G revenues) (b) $0.41 - 0.46 $0.41 - 0.46 $0.41 - 0.46
General and
administrative $0.20 - 0.25 $0.20 - 0.25 $0.22 - 0.27
Stock-based
compensation (non-
cash) $0.08 - 0.10 $0.08 - 0.10 $0.08 - 0.10
DD&A of oil and
natural gas assets $2.40 - 2.60 $2.40 - 2.60 $2.50 - 2.70
Depreciation of other
assets $0.22 - 0.24 $0.24 - 0.28 $0.28 - 0.32
Interest expense(c) $0.55 - 0.60 $0.60 - 0.65 $0.60 - 0.65
Other Income per Mcfe:
Oil and natural gas
marketing income $0.06 - 0.08 $0.06 - 0.08 $0.06 - 0.08
Service operations
income $0.08 - 0.12 $0.08 - 0.12 $0.08 - 0.12
Book Tax Rate (About
Equals 95% deferred) 38% 38% 38%
Equivalent Shares
Outstanding - in
millions:
Basic 452 453 458
Diluted 518 519 524
Capital Expenditures -
in millions:
Drilling, leasehold
and seismic $1,100 -1,200 $4,700 - 4,900 $4,700 -4,900
(a) Oil NYMEX prices have been updated for actual contract prices
through January 2007 and natural gas NYMEX prices have been updated
for actual contract prices through February 2007.
(b) Severance tax per mcfe is based on NYMEX prices of $55.62 per
bbl of oil and $7.40 to $8.40 per mcf of natural gas during Q1 2007,
$56.09 per bbl of oil and $7.50 to $8.50 per mcf of natural gas during
calendar 2007 and $56.25 per bbl of oil and $7.50 to $8.50 per mcf of
natural gas during calendar 2008.
(c) 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, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, 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) Basis protection swaps are arrangements that guarantee a
price differential of oil or natural gas from a specified delivery
point. 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.
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 non-qualifying 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:
Total
Open Swap Lifted
Positions Total Gain per
Avg. Assuming as a % of Gains Mcf of
NYMEX Natural Estimated from Estimated
Open Strike 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
======== ====== ======= =========== =========== ========== ===========
2007:
--------
Q1 33.6 $9.33 139.0 24% $281.1 $2.02
Q2 63.5 $7.99 147.5 43% $113.7 $0.77
Q3 74.9 $8.19 159.0 47% $103.8 $0.65
Q4 83.2 $8.96 173.5 48% $116.3 $0.67
======== ====== ======= =========== =========== ========== ===========
Total
2007(1) 255.2 $8.54 619.0 41% $614.9 $0.99
======== ====== ======= =========== =========== ========== ===========
======== ====== ======= =========== =========== ========== ===========
Total
2008(1) 378.7 $9.32 701.0 54% $105.0 $0.15
======== ====== ======= =========== =========== ========== ===========
======== ====== ======= =========== =========== ========== ===========
Total
2009(1) 35.6 $8.25 750.0 5% $3.9 $0.01
======== ====== ======= =========== =========== ========== ===========
(1) Certain hedging arrangements include swaps with knockout
prices ranging from $5.25 to $6.50 covering 146 bcf in 2007, $5.75 to
$6.50 covering 160 bcf in 2008 and $5.90 to $6.25 covering 36 bcf in
2009.
The company currently has the following open natural gas collars
in place:
Open Swap
Positions
Assuming as a % of
Natural Estimated
Gas Total
Open Avg. NYMEX Avg. NYMEX Production Natural
Swaps Floor Ceiling in Bcf's Gas
in Bcf's Price Price of: Production
============== ========= ========== ========== =========== ===========
2007:
--------------
Q1 -- -- -- 139.0 0%
Q2 21.8 $6.76 $8.20 147.5 15%
Q3 22.1 $6.76 $8.20 159.0 14%
Q4 19.6 $7.13 $8.88 173.5 11%
============== ========= ========== ========== =========== ===========
Total 2007(1) 63.5 $6.88 $8.41 619.0 10%
============== ========= ========== ========== =========== ===========
============== ========= ========== ========== =========== ===========
Total 2008(1) 21.3 $7.38 $9.20 701.0 3%
============== ========= ========== ========== =========== ===========
(1) Certain collar arrangements include knockout prices ranging
from $5.00 to $6.00 covering 52 bcf in 2007 and $5.00 to $6.00
covering 11 bcf in 2008.
Note: Not shown above are written call options covering 64.4 bcf
of production in 2007 at a weighted average price of $9.56 for a
weighted average premium of $0.54, 93.0 bcf of production in 2008 at a
weighed average price of $10.20 for a weighted average premium of
$0.70 and 42.9 bcf of production in 2009 at a weighed average price of
$11.41 for a weighted average premium of $0.50.
The company has the following natural gas basis protection swaps
in place:
Mid-Continent Appalachia
------------------------- ---------------------------
Volume in NYMEX Volume in NYMEX
Bcf's less(1): Bcf's plus(1):
----------- ------------- ------------- -------------
2007 176.6 0.43 36.5 0.35
2008 118.6 0.27 36.6 0.35
2009 86.6 0.29 18.2 0.31
----------- ------------- ------------- -------------
Totals 381.8 $0.35 91.3 $0.34
=========== ============= ============= =============
(1) 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 ($357 million as of December 31, 2006). 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:
Avg. Open Swap
NYMEX Positions
Strike Avg. Fair Assuming as a % of
Price Value Upon Natural Estimated
Open Of Open Acquisition Initial Gas Total
Swaps Swaps of Open Liability Production Natural
in (per Swaps Acquired in Bcf's Gas
Bcf's Mcf) (per Mcf) (per Mcf) of: Production
-------- ------ ------- ------------ --------- ----------- -----------
2007:
Q1 10.3 $4.82 $10.97 ($6.15) 139.0 7%
Q2 10.5 $4.82 $8.48 ($3.66) 147.5 7%
Q3 10.6 $4.82 $8.45 ($3.63) 159.0 7%
Q4 10.6 $4.82 $8.87 ($4.05) 173.5 6%
======== ====== ======= ============ ========= =========== ===========
Total
2007(1) 42.0 $4.82 $9.18 ($4.36) 619.0 7%
======== ====== ======= ============ ========= =========== ===========
======== ====== ======= ============ ========= =========== ===========
Total
2008(1) 38.4 $4.68 $8.02 ($3.34) 701.0 5%
======== ====== ======= ============ ========= =========== ===========
======== ====== ======= ============ ========= =========== ===========
Total
2009 18.3 $5.18 $7.28 ($2.10) 750.0 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 $6.00.
The company also has the following crude oil swaps in place:
Open Swap Total Total
Positions Gains Lifted
Assuming as a % from Gain per
Open Avg. Oil of Lifted bbl of
Swaps NYMEX Production Estimated Swaps Estimated
in Strike in mbbls Total Oil ($ Total Oil
mbbls Price of: Production millions) Production
--------- ------ ------- ---------- ----------- ---------- -----------
2007:
Q1 1,173 $71.98 2,095 56% $2.5 $1.19
Q2 1,274 $72.12 2,120 60% $2.1 $0.99
Q3 1,288 $71.89 2,140 60% $2.1 $0.99
Q4 1,288 $71.61 2,145 60% $2.1 $0.98
========= ====== ======= ========== =========== ========== ===========
Total
2007(1) 5,023 $71.90 8,500 59% $8.8 $1.04
========= ====== ======= ========== =========== ========== ===========
========= ====== ======= ========== =========== ========== ===========
Total
2008(1) 4,300 $71.63 8,500 51% $4.8 $0.57
========= ====== ======= ========== =========== ========== ===========
========= ====== ======= ========== =========== ========== ===========
Total
2009(1) 183 $66.10 8,500 2% -- --
========= ====== ======= ========== =========== ========== ===========
(1) Certain hedging arrangements include swaps with knockout
prices ranging from $45.00 to $60.00 covering 1,460 mbbls in 2007 and
$45.00 to $60.00 covering 1,098 mbbls in 2008.
SOURCE: Chesapeake Energy Corporation
Chesapeake Energy Corporation, Oklahoma City
Jeffrey L. Mobley, CFA, 405-767-4763
Senior Vice President - Investor Relations and Research
jmobley@chkenergy.com
or
Marc Rowland, 405-879-9232
Executive Vice President and Chief Financial Officer
mrowland@chkenergy.com