Printer Friendly Version (pdf format)
Net Income Available to Common Shareholders Reaches $332 Million on Revenue of
$1.6 Billion and Production of 143 Bcfe; Net Income Per Fully Diluted Common
Share Increases 58% Over the 2005 Second Quarter
Total Production Growth Should Reach at Least 25% in 2006 and 11% in 2007,
Including 10% Organic Production Growth in Each Year
Proved Reserves Reach Record Level of 8.1 Tcfe; Company Delivers First Half
2006 Reserve Replacement Rate of 308% From 860 Bcfe of Additions at a Drilling
and Acquisition Cost of $1.80 per Mcfe
Company Provides Detailed Review of Its 14.0 Tcfe of Unproved Reserves Located
on Its 9.7 Million Net Acre U.S. Onshore Leasehold Position
OKLAHOMA CITY, July 27 /PRNewswire-FirstCall/ -- Chesapeake Energy
Corporation (NYSE: CHK) today reported financial and operating results for the
second quarter of 2006. For the quarter, Chesapeake generated net income
available to common shareholders of $332.1 million ($0.82 per fully diluted
common share), operating cash flow of $914.2 million (defined as cash flow
from operating activities before changes in assets and liabilities) and ebitda
of $1.029 billion (defined as net income before income taxes, interest
expense, and depreciation, depletion and amortization expense) on revenue of
$1.584 billion and production of 142.7 billion cubic feet of natural gas
equivalent (bcfe). For the quarter, ebitda and net income per fully diluted
common share increased 77% and 58% over the 2005 second quarter, respectively.
The company's 2006 second quarter net income available to common
shareholders and ebitda include various items that are typically not included
in published estimates of the company's financial results by certain
securities analysts. Such items and their after-tax effects on 2006 second
quarter reported results are described as follows:
* an unrealized mark-to-market gain of $9.7 million resulting from the
company's oil and natural gas and interest rate hedging programs;
* a reversal of an accrual of $7.2 million for production taxes as the
result of the dismissal of certain severance tax claims;
* a $15.0 million income tax accrual related to the recently adopted
"margin" tax in Texas; and
* a reduction of net income available to common shareholders of
$9.5 million resulting from the exchange of two series of the
company's preferred stock for common stock pursuant to tender offers
made during the quarter.
Excluding the above-mentioned items and giving effect to common shares
issued for preferred shares during the quarter, Chesapeake's net income to
common shareholders in the second quarter of 2006 would have been
$339.8 million ($0.82 per fully diluted common share) and ebitda would have
been $1.001 billion. The foregoing items do not affect the calculation of
operating cash flow. For the quarter, adjusted ebitda and adjusted net income
per fully diluted common share increased 77% and 64% over the 2005 second
quarter. A reconciliation of operating cash flow, ebitda, adjusted ebitda and
adjusted net income to comparable financial measures calculated in accordance
with generally accepted accounting principles is presented on pages 18-21 of
this release.
Key Operational and Financial Statistics Summarized Below
for the 2006 Second Quarter
The table below summarizes Chesapeake's key results during the 2006 second
quarter and compares them to the 2006 first quarter and the 2005 second
quarter.
Three Months Ended:
6/30/06 3/31/06 6/30/05
Average daily production (in mmcfe) 1,568 1,519 1,244
Natural gas as % of total production 91 91 89
Natural gas production (in bcf) 129.8 124.1 101.1
Average realized natural gas price ($/mcf)(A) 8.04 9.61 5.95
Oil production (in mbbls) 2,143 2,116 2,012
Average realized oil price ($/bbl)(A) 58.80 57.12 42.82
Natural gas equivalent production (in bcfe) 142.7 136.8 113.2
Natural gas equivalent realized
price ($/mcfe)(A) 8.20 9.60 6.08
Marketing income ($/mcfe) .08 .10 .05
Service operations income ($/mcfe) .10 .11 ---
Production expenses ($/mcfe) (.85) (.87) (.64)
Production taxes ($/mcfe)(B) (.24) (.40) (.42)
General and administrative costs ($/mcfe)(C) (.19) (.17) (.08)
Stock-based compensation ($/mcfe) (.05) (.05) (.02)
DD&A of oil and natural
gas properties ($/mcfe) (2.30) (2.23) (1.85)
D&A of other assets ($/mcfe) (.16) (.17) (.10)
Interest expense ($/mcfe)(A) (.51) (.52) (.48)
Operating cash flow ($ in millions)(D) 914.2 1,046.9 453.7
Operating cash flow ($/mcfe) 6.41 7.66 4.01
Adjusted ebitda ($ in millions)(E) 1,001.4 1,147.2 564.6
Adjusted ebitda ($/mcfe) 7.02 8.39 4.99
Net income to common shareholders
($ in millions) 332.1 603.9 179.2
Earnings per share - assuming dilution ($) 0.82 1.44 0.52
Adjusted net income to common
shareholders ($ in millions)(F) 339.8 444.2 173.9
Adjusted earnings per share
- assuming dilution ($) 0.82 1.07 0.50
(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) current quarter includes an $11.6 million reversal of an Oklahoma
severance tax accrual
(C) excludes expenses associated with non-cash stock-based compensation
(D) defined as cash flow provided by operating activities before changes
in assets and liabilities
(E) 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.
(F) defined as net income as adjusted to remove the effects of certain
items detailed on page 20.
Oil and Natural Gas Production Sets Record for 20th Consecutive Quarter;
2006 Second Quarter Average Daily Production Increases 26% and 3%
Over Production in the 2005 Second Quarter and the 2006 First Quarter
Daily production for the 2006 second quarter averaged 1.568 bcfe, an
increase of 324 million cubic feet of natural gas equivalent (mmcfe), or 26%,
over the 1.244 bcfe of daily production in the 2005 second quarter and an
increase of 49 mmcfe, or 3.2%, over the 1.519 bcfe produced per day in the
2006 first quarter. Of the 324 mmcfe increase in daily production from the
year ago quarter, 45% was generated from organic drillbit growth and 55% was
generated from acquisitions, with the company's trailing 12-month organic
production growth rate calculated as 12.0%.
Of the 49 mmcfe daily increase in sequential quarterly production, 95% was
generated from organic drillbit growth and 5% was generated from acquisitions,
with the company's sequential quarterly organic production growth rate
calculated as 3.1%. Chesapeake is anticipating total production growth of at
least 25% in 2006 and 11% in 2007, including organic growth rates of at least
10% each year. Please note that the company's production forecast for 2006
excludes any provision for possible production curtailments that the industry
and Chesapeake may experience as a result of high pipeline pressures and/or
early filling of U.S. natural gas storage facilities.
Chesapeake's 2006 second quarter production of 142.7 bcfe was comprised of
129.8 billion cubic feet of natural gas (bcf) (91% on a natural gas equivalent
basis) and 2.14 million barrels of oil and natural gas liquids (mmbbls) (9% on
a natural gas equivalent basis). Chesapeake's average daily production for
the quarter of 1.568 bcfe consisted of 1.427 bcf of natural gas and 23,549
barrels (bbls) of oil. The 2006 second quarter was Chesapeake's 20th
consecutive quarter of sequential U.S. production growth. Over these
20 quarters, Chesapeake's U.S. production has increased 296%, for an average
compound quarterly growth rate of 7.1% and an average compound annual growth
rate of 31.7%.
Chesapeake Continues Industry's Most Active Drilling Program With Drilling
Success Rate Over 97%
Chesapeake's exploratory and development drilling programs and production
enhancement operations on its existing and acquired properties continue to
produce operational results that distinguish the company among its peers.
During the 2006 first half, Chesapeake continued the industry's most active
drilling program and drilled 613 gross (496 net) operated wells and
participated in another 801 gross (88 net) wells operated by other companies.
The company's drilling success rate was 97% for company-operated wells and 99%
for non-operated wells. During the 2006 first half, Chesapeake invested
$1.097 billion in operated wells (using an average of 82 operated rigs),
$241 million in non-operated wells (using an average of 75 non-operated rigs),
$324 million to acquire new leasehold (exclusive of leases acquired through
acquisitions) and $72 million to acquire new 3-D seismic data.
During the First Half of 2006, Oil and Natural Gas Proved Reserves Reach
Record Level of 8.1 Tcfe; Drilling and Acquisition Costs Average $1.80 per
Mcfe as Company Adds 860 Bcfe for a Reserve Replacement Rate of 308%
Chesapeake began 2006 with estimated proved reserves of 7.521 trillion
cubic feet of natural gas equivalent (tcfe) and ended the second quarter with
8.101 tcfe, an increase of 580 bcfe, or 7.7%. During the 2006 first half,
Chesapeake replaced its 279 bcfe of production with an estimated 860 bcfe of
new proved reserves, for a reserve replacement rate of 308%. Reserve
replacement through the drillbit was 590 bcfe, or 211% of production
(including 352 bcfe of positive performance revisions and 196 bcfe of downward
revisions resulting from natural gas price declines between December 31, 2005
and June 30, 2006) and 69% of the total increase. Reserve replacement through
the acquisition of proved reserves was 269 bcfe, or 97% of production and 31%
of the total increase.
Total costs incurred during the 2006 first half, including drilling,
completion, acquisition, seismic, leasehold, capitalized internal costs, non-
cash tax basis step-up from corporate acquisitions, asset retirement
obligations and all other miscellaneous costs capitalized to oil and natural
gas properties, were $3.6 billion. The company's total drilling and
acquisition costs were $1.80 per thousand cubic feet of natural gas equivalent
(mcfe), excluding costs of $1.6 billion for leasehold and unproved properties
acquired during the period and $93 million relating primarily to tax basis
step-up and asset retirement obligations, as well as downward revisions of
proved reserves from lower natural gas prices. Excluding the same costs as
described above, Chesapeake's exploration and development costs through the
drillbit were $1.70 per mcfe during the 2006 first half while reserve
replacement costs through acquisitions of proved reserves were $1.84 per mcfe.
A complete reconciliation of finding and acquisition costs and a roll-forward
of proved reserves is presented on page 16 of this release.
As of June 30, 2006, the estimated future net cash flows of Chesapeake's
proved reserves, before income taxes and discounted at 10% (PV-10), were
$15.0 billion using field differential adjusted prices of $69.10 per barrel of
oil (bbl) (based on a NYMEX quarter-ending price of $73.86 per bbl) and
$5.72 per thousand cubic feet of natural gas (mcf) (based on a NYMEX quarter-
ending price of $6.09 per mcf). 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 securities and other non-current
assets) was $1.8 billion as of June 30, 2006.
Chesapeake's PV-10 changes by approximately $310 million for every
$0.10 per mcf change in natural gas prices and approximately $49 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 June 30, 2006 PV-10 value to the standardized measure at such
date. 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.
Average Prices Realized, Hedging Results and Hedging Positions Detailed
Average prices realized during the 2006 second quarter (including realized
gains or losses from oil and natural gas derivatives, but excluding unrealized
gains or losses on such derivatives) were $58.80 per bbl and $8.04 per mcf,
for a realized natural gas equivalent price of $8.20 per mcfe. Chesapeake's
average realized pricing differentials to NYMEX during the second quarter were
a negative $6.19 per bbl and a negative $0.84 per mcf. Realized gains and
losses from oil and natural gas hedging activities during the quarter
generated a $5.71 loss per bbl and a $2.08 gain per mcf, for a 2006 second
quarter realized hedging gain of $257.4 million, or $1.80 per mcfe.
Chesapeake's total realized hedging gains in the first half of 2006 were
$505.6 million, or $1.81 per mcfe.
Chesapeake has hedged a substantial level of its production through 2008
in order to capture attractive returns from recent acquisitions and to help
secure strong margins and profitability on the company's drilling program.
The following tables compare Chesapeake's hedged production volumes (including
only swaps and also including the hedges assumed in the CNR acquisition) as of
July 27, 2006 to those as of June 5, 2006.
Swap Positions as of July 27, 2006
Natural Gas Oil
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2006 3Q 93% $8.85 87% $64.83
2006 4Q 87% $9.50 86% $65.64
2006 Total Remaining 90% $9.17 87% $65.25
2007 Total 72% $9.88 73% $71.42
2008 Total 57% $9.37 63% $71.45
Swap Positions as of June 5, 2006
Natural Gas Oil
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2006 3Q 93% $8.85 84% $63.90
2006 4Q 86% $9.50 85% $63.76
2006 Total Remaining 89% $9.17 84% $63.83
2007 Total 69% $9.86 56% $68.79
2008 Total 55% $9.34 48% $69.50
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.
The company's updated 2006 and 2007 forecasts are attached to this release
in an Outlook dated July 27, 2006 labeled as Schedule "A", which begins on
page 22. This Outlook has been changed from the Outlook dated June 5, 2006
(attached as Schedule "B", which begins on page 26) to reflect various updated
information.
Chesapeake Increases Cost Inflation Hedges through Additional Oilfield Service
Investments
Chesapeake recently agreed to purchase one of the leading drilling
contractors in the Appalachian Basin. The company is currently utilizing two
of the contractor's 15 rigs and through this acquisition will gain enhanced
operational flexibility in expanding activity levels in the basin. This
acquisition bolsters the scale and operating capabilities of the company's
100% owned drilling rig subsidiary, Nomac Drilling Corporation. To date,
Chesapeake has invested approximately $400 million to build or acquire
57 drilling rigs (including the pending acquisition of the Appalachian Basin
drilling contractor) and is building 22 additional rigs. In total,
Chesapeake's drilling rig fleet should reach 79 rigs by the end of the 2007
first quarter, which would rank Nomac as one of the six largest drilling rig
contractors in the U.S.
Chesapeake's direct rig ownership is complemented by its $63 million in
investments in two private drilling rig contractors, DHS Drilling Company and
Mountain Drilling Company, in which Chesapeake owns approximately 45% and 49%,
respectively. DHS owns 16 rigs and Mountain owns four rigs and has ordered
another six rigs for delivery later in 2006 and 2007. Chesapeake's rig
investments have served as an effective hedge to rising service costs and have
also provided competitive advantages in making acquisitions and in developing
its own leasehold on a more timely and efficient basis.
Chesapeake's Leasehold and 3-D Seismic Inventories Now 9.7 Million Net Acres
and 12.9 Million Acres; Risked Unproved Reserves in the Company's Inventory
Now 14.0 Tcfe, Bringing Total Reserve Base to 22.1 Tcfe
Chesapeake attributes its strong drilling results and organic growth rates
during 2006 (and in this decade) to management's early recognition that oil
and natural gas prices were undergoing structural change and its subsequent
decision to invest aggressively in the building blocks of value creation in
the E&P industry - people, land and science. During the past five years,
Chesapeake has significantly strengthened its technical capabilities by
increasing its land, geoscience and engineering staff by over 450% to nearly
800 employees. Today, the company has more than 4,100 employees, of which
approximately 70% work in the company's E&P operations and approximately 30%
work in the company's oilfield service operations.
Since 2000, Chesapeake has invested $4.7 billion in new leasehold and 3-D
seismic acquisitions and now owns what it believes to be one of the largest
inventories of onshore leasehold (9.7 million net acres) and 3-D seismic
(12.9 million acres) in the U.S. On this leasehold, the company has an
estimated 24,000 net drilling locations, representing an approximate 10-year
inventory of drilling projects, on which it believes it can develop
approximately 3.3 tcfe of proved undeveloped reserves and approximately
14.0 tcfe of unproved reserves. Adding the company's total proved reserves of
8.1 tcfe to its estimated 14.0 tcfe of unproved reserves brings Chesapeake's
estimated total reserves to approximately 22.1 tcfe.
Company Provides Detailed Information on Its Four Gas Resource Play Types
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 position 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, 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 10.0 million
acres of 3-D seismic data. In these plays, Chesapeake owns 3.0 million net
acres on which it has an estimated 1.0 tcfe of proved undeveloped reserves, an
estimated 2.4 tcfe of risked unproved reserves and is currently utilizing
31 operated drilling rigs (up to 32 by year-end) to further develop its
inventory of approximately 2,800 drillsites. Two of Chesapeake's most
important conventional gas resource plays are described below.
* South Texas: Located primarily in Zapata County, Texas, Chesapeake's
South Texas assets are currently producing approximately 145 mmcfe per
day and the company is currently utilizing six rigs (up to seven by
year-end) to develop its 140,000 net acres of leasehold. Chesapeake's
proved undeveloped reserves in South Texas are an estimated 211 bcfe
and its risked unproved reserves are an estimated 300 bcfe after
applying a 75% risk factor and assuming an additional 325 net wells
are drilled in the years ahead. The company's expected economics for
vertical South Texas wells are $3.0 million to develop 2.0 bcfe on
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 currently producing approximately 80 mmcfe per
day from the Mountain Front area and is currently utilizing four rigs
(four at year-end also) to develop its 120,000 net acres of leasehold.
Chesapeake's proved undeveloped reserves in the Mountain Front are an
estimated 65 bcfe and its risked unproved reserves are an estimated
200 bcfe after applying a 70% risk factor and assuming an additional
80 net wells are drilled in the years ahead. The company's expected
economics for vertical Mountain Front wells are $8.0 million to
develop 4.0 bcfe on 320 acre spacing.
Unconventional Gas Resource Plays - In its unconventional gas resource
areas, Chesapeake owns 1.1 million net acres on which it has an estimated
1.7 tcfe of proved undeveloped reserves, an estimated 6.0 tcfe of risked
unproved reserves and is currently utilizing 51 operated drilling rigs (up to
69 by year-end) to further develop its inventory of approximately 9,000 net
drillsites. Four of Chesapeake's most important unconventional gas resource
plays are described below.
* Fort Worth Barnett Shale (North Texas): This play is the largest
unconventional gas resource play in the U.S. and Chesapeake believes
it is the third largest producer of natural gas and the third most
active driller as well as the second largest leasehold owner in
Tarrant and Johnson Counties (the sweet spot of the horizontally
developed "Tier 1" area). Chesapeake is currently producing
approximately 130 mmcfe per day from the Fort Worth Barnett Shale and
is currently utilizing 15 rigs (up to 25 by year-end) to develop its
165,000 net acres of leasehold located primarily in the Tier 1 area.
Chesapeake's proved undeveloped reserves in the Fort Worth Barnett are
an estimated 594 bcfe and its risked unproved reserves are an
estimated 3.4 tcfe after applying a 25% risk factor and assuming an
additional 2,200 net wells are drilled in the years ahead. The
company's expected economics for horizontal Barnett Shale wells are
$2.7 million to develop 2.4 bcfe on 55 acre spacing.
* Sahara (Primarily Mississippi, Chester, Hunton formations in Northwest
Oklahoma): In this vast play that extends across five counties in
northwestern Oklahoma, Chesapeake believes it is the largest producer
of natural gas, the most active driller and the largest leasehold
owner in the area. Chesapeake is currently producing approximately
130 mmcfe per day in the Sahara area and is currently utilizing
12 rigs (up to 16 by year-end) to develop its 500,000 net acres of
leasehold. Chesapeake's proved undeveloped reserves in Sahara are an
estimated 397 bcfe and its risked unproved reserves are an estimated
1.8 tcfe after applying a 25% risk factor and assuming an additional
4,900 net wells are drilled in the years ahead. The company's
expected economics for vertical Sahara wells are $0.9 million to
develop 0.6 bcfe on approximately 65 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 believes
it is one of the 10 largest producers of natural gas, the third most
active driller and one of the largest leasehold owners in the area.
Chesapeake is currently producing approximately 100 mmcfe per day in
the Ark-La-Tex area and is currently utilizing 14 rigs (up to 17 by
year-end) to further develop its 125,000 net acres of leasehold.
Chesapeake's unconventional proved undeveloped reserves in the Ark-La-
Tex region are an estimated 369 bcfe and its unconventional risked
unproved reserves are an estimated 425 bcfe after applying a 40% risk
factor and assuming an additional 1,100 net wells are drilled in the
years ahead. The company's expected economics for medium-depth
vertical unconventional Ark-La-Tex wells are $1.6 million to develop
1.0 bcfe on approximately 60 acre spacing.
* Granite, Atoka and Cherokee Washes (Western Oklahoma and Texas
Panhandle): Chesapeake believes it is the largest producer of natural
gas, the most active driller and the largest leasehold owner in the
Wash plays. Chesapeake is currently producing approximately 110 mmcfe
per day from these plays and is currently utilizing 10 rigs (up to 11
by year-end) to further develop its 115,000 net acres of leasehold.
Chesapeake's proved undeveloped reserves in the Wash plays are an
estimated 304 bcfe and its risked unproved reserves are an estimated
300 bcfe after applying a 50% risk factor and assuming an additional
525 net wells are drilled in the years ahead. The company's expected
economics for vertical Wash wells are $2.8 million to develop 1.4 bcfe
on 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 2.2 million net acres on which it has an
estimated 100 bcfe of proved undeveloped reserves, an estimated 3.8 tcfe of
risked unproved reserves and is currently utilizing 10 operated drilling rigs
(up to 23 rigs by year-end) to further develop its inventory of approximately
2,600 net drillsites. Five of Chesapeake's most important emerging
unconventional gas resource plays are described below.
* Fayetteville Shale (Arkansas): In this region of rapidly growing
importance to Chesapeake, the company believes it is now the largest
leasehold owner in the play (second largest in the most currently
prospective area of the play). Chesapeake is currently producing
approximately 2.0 mmcfe per day from the Fayetteville Shale and is
currently utilizing two rigs (up to eight by year-end) to further
develop its 1.0 million net acres of leasehold (300,000 net acres in
the most currently prospective area of the play to date).
Chesapeake's proved undeveloped reserves in the Fayetteville are an
estimated 18 bcfe and its risked unproved reserves are an estimated
2.0 tcfe after applying an 85% risk factor and assuming an additional
2,000 net wells are drilled in the years ahead. The company's
expected economics for horizontal Fayetteville Shale wells are
$2.5 million to develop 1.2 bcfe on 80 acre spacing.
* Deep Haley (Primarily Strawn, Atoka, Morrow formations in West Texas):
In this West Texas Delaware Basin area of increasing value to
Chesapeake, the company believes it is now the second largest
leasehold owner. Chesapeake is currently producing approximately
30 mmcfe per day from the Deep Haley area and is currently utilizing
four rigs (up to eight by year-end) to further develop its 225,000 net
acres of leasehold. Chesapeake's proved undeveloped reserves in Deep
Haley are an estimated 59 bcfe and its risked unproved reserves are an
estimated 650 bcfe after applying an 80% risk factor and assuming an
additional 140 net wells are drilled in the years ahead. The
company's expected economics for vertical Deep Haley wells are
$10.5 million to develop 7.0 bcfe on 320 acre spacing.
* Delaware Basin Shales (Primarily Barnett and Woodford formations in
West Texas): Chesapeake's most significant land acquisition
activities during the 2006 second quarter took place in the Delaware
Basin Barnett and Woodford Shale play in far West Texas. In this
promising play, Chesapeake believes it has become the second largest
leasehold owner (and the largest in what it believes is the most
prospective area of the play). Chesapeake is currently producing
approximately 1.0 mmcfe per day from the Delaware Basin Barnett and
Woodford Shales and is currently utilizing two rigs (up to four by
year-end) to further develop its 385,000 net acres of leasehold.
Chesapeake has not yet booked any proved reserves in the Delaware
Basin shales plays and its risked unproved reserves are an estimated
600 bcfe after applying a 90% risk factor and assuming an additional
240 net wells are drilled in the years ahead. The company's expected
economics for Delaware Basin vertical Barnett and Woodford Shale wells
are $4.5 million to develop 3.0 bcfe on 160 acre spacing.
* Caney and Woodford Shales (Oklahoma Arkoma Basin): Chesapeake
believes it is now the third largest leasehold owner in the Caney and
Woodford Shale play, one of the most promising unconventional gas
plays in the Oklahoma portion of the Arkoma Basin. The company is
currently producing approximately 7.0 mmcfe per day from the Caney and
Woodford Shales and is currently utilizing one rig to drill its first
operated horizontal Woodford Shale well on its 100,000 net acres of
leasehold. Chesapeake's proved undeveloped reserves in the play are
an estimated 10 bcfe and its risked unproved reserves are an estimated
300 bcfe after applying a 70% risk factor and assuming an additional
170 net wells are drilled in the years ahead. The company's expected
economics for horizontal Woodford Shale wells are $4.0 million to
develop 2.2 bcfe on 160 acre spacing.
* Deep Bossier (East Texas and Northern Louisiana): Chesapeake believes
it has become one of the top three leasehold owners in the emerging
Deep Bossier play. The company is currently producing approximately
1.0 mmcfe per day in the Deep Bossier play and is currently utilizing
one rig (one or two by year-end) to further develop its 190,000 net
acres of leasehold. Chesapeake's proved undeveloped reserves in the
Deep Bossier play are an estimated 6.0 bcfe and its risked unproved
reserves are an estimated 200 bcfe after applying a 90% risk factor
and assuming an additional 60 net wells are drilled in the years
ahead. The company's expected economics for Deep Bossier wells are
$10.0 million to develop 5.0 bcfe on 320 acre spacing.
Appalachian Basin Gas Resource Plays - In this core area of the company's
operations, play types range from conventional to unconventional to emerging
gas resource in various Devonian Shale and other formations. Chesapeake is
the largest leasehold owner in the region with 3.4 million net acres that were
primarily acquired from CNR in November 2005. The company is currently
producing approximately 120 mmcfe per day and is currently utilizing nine rigs
(up to 11 rigs by year-end) to further develop its extensive leasehold
position. In Appalachia, Chesapeake has an estimated 468 bcfe of proved
undeveloped reserves and its risked unproved reserves are an estimated
1.8 tcfe after applying a 35% risk factor and assuming an additional 9,100 net
wells are drilled in the years ahead. The company's expected economics for
vertical Devonian Shale wells are $0.425 million to develop 0.3 bcfe on
160 acre spacing.
In addition, Chesapeake continues to actively develop various
conventional, unconventional and emerging unconventional plays not described
above. These areas are located throughout the company's operations and in
which the company continues to actively generate new prospects and acquire
additional leasehold.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We
are pleased to again report outstanding financial and operational results for
the 2006 second quarter. The company delivered top-tier organic production
growth and impressive profit margins as strong oil and natural gas price
realizations far exceeded modest cost inflation. We have also
opportunistically hedged service costs and a substantial portion of our
anticipated production through 2008 at exceptional prices in order to ensure
strong profitability. This position differentiates Chesapeake among many
companies in the industry that may face margin compression as natural gas
markets digest short-term excess natural gas supplies caused in large part by
limited storage capacity and exceptionally warm weather last winter.
"In light of continued strong returns available through the drillbit on
our extensive prospect inventory, we continue to increase our industry-leading
U.S. drilling activity to accelerate development of our substantial unproved
reserve base. We currently have 101 operated rigs working, up from an average
of 73 operated rigs in 2005, and we anticipate increasing our drilling
activity to approximately 135 operated rigs by year-end 2006. This increase
in drilling activity creates the potential for increased proved reserves and
production levels in 2006 and 2007.
"Our business strategy continues to feature delivering growth through a
balance of acquisitions and organic drilling, focusing on clean-burning,
domestically-produced natural gas to take advantage of strong long-term
natural gas supply and demand fundamentals, building dominant regional scale
to achieve low operating costs and high returns on capital and mitigating
financial and operational risks through hedging. We believe Chesapeake's
management team can continue the successful execution of the company's
distinctive business strategy and continue to deliver significant value to the
company's investors for years to come."
Conference Call Information
A conference call to discuss this release has been scheduled for Friday
morning, July 28, 2006 at 9:00 a.m. EDT. The telephone number to access the
conference call is 913-981-5543 and the confirmation code is 4119635. We
encourage those who would like to participate in the call to dial the access
number between 8:50 and 8:55 am EDT. For those unable to participate in the
conference call, a replay will be available for audio playback from noon EDT,
July 28, 2006 through midnight EDT on August 10, 2006. The number to access
the conference call replay is 719-457-0820 and the passcode for the replay is
4119635. The conference call will also be webcast live on the Internet and
can be accessed by going to Chesapeake's website at http://www.chkenergy.com
and selecting the "News & Events" section. The webcast of the conference call
will be available on our website indefinitely.
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.
Factors that could cause actual results to differ materially from expected
results are described under "Risk Factors" in the Prospectus dated
June 27, 2006 for our offering of 7.625% Senior Notes due 2013 filed with the
Securities and Exchange Commission on June 29, 2006. 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; and drilling and operating risks. We
caution you not to place undue reliance on these forward-looking statements,
which speak only as of the date of this press release, and we undertake no
obligation to update this information.
Our production forecasts are dependent upon many assumptions, including
estimates of production decline rates from existing wells and the outcome of
future drilling activity. Our production forecasts exclude provisions for
possible production curtailments that the industry and Chesapeake may
experience as a result of high pipeline pressures and/or early filling of U.S.
natural gas storage facilities. Also, our internal estimates of reserves,
particularly those in the properties recently acquired or proposed to be
acquired where we may have limited review of data or experience with the
reserves, may be subject to revision and may be different from estimates by
our external reservoir engineers at year-end. 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 terms "probable", "possible" or "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 being actually 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 second largest independent 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, Permian Basin, South Texas,
Texas Gulf Coast, Barnett Shale, Ark-La-Tex and Appalachian Basin regions of
the United States. The company's Internet address is
http://www.chkenergy.com .
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
THREE MONTHS ENDED: June 30, June 30,
2006 2005
$ $/mcfe $ $/mcfe
REVENUES:
Oil and natural gas sales 1,186,383 8.32 772,401 6.83
Marketing sales 367,610 2.57 275,617 2.43
Service operations revenue 30,023 0.21 --- ---
Total Revenues 1,584,016 11.10 1,048,018 9.26
OPERATING COSTS:
Production expenses 120,697 0.85 72,333 0.64
Production taxes 33,923 0.24 47,253 0.42
General and administrative
expenses 33,555 0.24 11,788 0.10
Marketing expenses 355,688 2.48 270,003 2.39
Service operations expense 15,667 0.11 --- ---
Oil and natural gas
depreciation, depletion
and amortization 328,159 2.30 209,371 1.85
Depreciation and amortization
of other assets 23,163 0.16 11,807 0.10
Total Operating Costs 910,852 6.38 622,555 5.50
INCOME FROM OPERATIONS 673,164 4.72 425,463 3.76
OTHER INCOME (EXPENSE):
Interest and other income
4,974 0.03 2,005 0.02
Interest expense (73,456) (0.51) (53,902) (0.48)
Loss on repurchases or
exchanges of Chesapeake debt --- --- (68,400) (0.60)
Total Other Income (Expense) (68,482) (0.48) (120,297) (1.06)
Income Before Income Taxes 604,682 4.24 305,166 2.70
Income Tax Expense:
Current --- --- --- ---
Deferred 244,779 1.72 111,387 0.99
Total Income Tax Expense 244,779 1.72 111,387 0.99
NET INCOME 359,903 2.52 193,779 1.71
Preferred stock dividends (18,228) (0.12) (9,859) (0.09)
Loss on exchange/conversion
of preferred stock (9,547) (0.07) (4,743) (0.04)
NET INCOME AVAILABLE
TO COMMON SHAREHOLDERS 332,128 2.33 179,177 1.58
EARNINGS PER COMMON SHARE:
Basic $0.87 $0.58
Assuming dilution $0.82 $0.52
WEIGHTED AVERAGE COMMON
AND COMMON EQUIVALENT SHARES
OUTSTANDING (in 000's)
Basic 380,675 311,181
Assuming dilution 428,169 364,063
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
SIX MONTHS ENDED: June 30, June 30,
2006 2005
$ $/mcfe $ $/mcfe
REVENUES:
Oil and natural gas sales 2,697,204 9.66 1,311,343 6.01
Marketing sales 771,977 2.76 520,125 2.39
Service operations revenue 59,402 0.21 --- ---
Total Revenues 3,528,583 12.63 1,831,468 8.40
OPERATING COSTS:
Production expenses 240,089 0.86 141,895 0.65
Production taxes 89,296 0.32 83,211 0.38
General and administrative expenses 62,346 0.22 23,855 0.11
Marketing expenses 747,048 2.67 507,279 2.33
Service operations expense 30,104 0.11 --- ---
Oil and natural gas depreciation,
depletion and amortization 633,116 2.27 390,339 1.79
Depreciation and amortization
of other assets 47,035 0.17 21,889 0.10
Employee retirement expense 54,753 0.20 --- ---
Total Operating Costs 1,903,787 6.82 1,168,468 5.36
INCOME FROM OPERATIONS 1,624,796 5.81 663,000 3.04
OTHER INCOME (EXPENSE):
Interest and other income 14,610 0.05 5,362 0.02
Interest expense (146,114) (0.52) (97,030) (0.44)
Gain on sale of investment 117,396 0.42 --- ---
Loss on repurchases or exchanges
of Chesapeake debt --- --- (69,300) (0.32)
Total Other Income (Expense) (14,108) (0.05) (160,968) (0.74)
Income Before Income Taxes 1,610,688 5.76 502,032 2.30
Income Tax Expense:
Current --- --- --- ---
Deferred 627,062 2.24 183,243 0.84
Total Income Tax Expense 627,062 2.24 183,243 0.84
NET INCOME 983,626 3.52 318,789 1.46
Preferred stock dividends (37,040) (0.13) (15,322) (0.07)
Loss on exchange/conversion
of preferred stock (10,556) (0.04) (4,743) (0.02)
NET INCOME AVAILABLE TO COMMON
SHAREHOLDERS 936,030 3.35 298,724 1.37
EARNINGS PER COMMON SHARE:
Basic $2.50 $0.96
Assuming dilution $2.27 $0.88
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in 000's)
Basic 374,683 310,523
Assuming dilution 433,414 356,478
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in 000's)
(unaudited)
June 30, December 31,
2006 2005
Cash $366,270 $60,027
Other current assets 1,289,467 1,123,370
Total Current Assets 1,655,737 1,183,397
Property and equipment (net) 17,775,369 14,411,887
Other assets 629,945 523,178
Total Assets $20,061,051 $16,118,462
Current liabilities $1,776,469 $1,964,088
Long term debt 6,330,115 5,489,742
Asset retirement obligation 171,430 156,593
Other long term liabilities 357,120 528,738
Deferred tax liability 2,435,731 1,804,978
Total Liabilities 11,070,865 9,944,139
STOCKHOLDERS' EQUITY 8,990,186 6,174,323
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY $20,061,051 $16,118,462
COMMON SHARES OUTSTANDING 418,876 370,190
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF SIX MONTHS ENDED JUNE 30, 2006 ADDITIONS TO OIL AND NATURAL
GAS PROPERTIES
($ in 000's, except per unit amounts)
(unaudited)
Reserves
Cost (in mmcfe) $/mcfe
Exploration and development costs $1,338,205 786,027(A) $1.70
Acquisition of proved properties
494,278 269,239 $1.84
Subtotal 1,832,483 1,055,266 $1.74
Divestitures (73) (89) ---
Geological and geophysical costs 71,675 --- ---
Adjusted subtotal 1,904,085 1,055,177 $1.80
Revisions - price --- (195,541) ---
Acquisition of unproved properties 1,256,132 --- ---
Leasehold acquisition costs 323,856 --- ---
Adjusted subtotal 3,484,073 859,636 $4.05
Tax basis step-up 81,373 ---
Asset retirement obligation and other 11,774 ---
Total $3,577,220 859,636 $4.16
(A) Includes positive performance revisions of 352 bcfe and excludes
downward revisions of 196 bcfe resulting from natural gas price
declines between December 31, 2005 and June 30, 2006.
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
(unaudited)
Mmcfe
Beginning balance, 12/31/05 7,520,690
Extensions and discoveries 434,414
Acquisitions 269,239
Divestitures (89)
Revisions - performance 351,613
Revisions - price (195,541)
Production (279,428)
Ending balance, 6/30/06 8,100,898
Reserve replacement 859,636
Reserve replacement rate 308%
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL AND NATURAL GAS SALES AND INTEREST EXPENSE
(in 000's)
(unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED
June 30, June 30,
2006 2005 2006 2005
Oil and Natural Gas Sales
($ in thousands):
Oil sales $138,241 $96,798 $262,908 $176,742
Oil derivatives
- realized gains (losses) (12,227) (10,650) (16,035) (17,717)
Oil derivatives - unrealized
gains (losses) (2,564) 10,900 (3,899) (1,942)
Total Oil Sales 123,450 97,048 242,974 157,083
Natural gas sales 774,259 635,901 1,714,577 1,171,678
Natural gas derivatives -
realized gains (losses) 269,650 (33,702) 521,679 13,713
Natural gas derivatives -
unrealized gains (losses) 19,024 73,154 217,974 (31,131)
Total Natural Gas Sales 1,062,933 675,353 2,454,230 1,154,260
Total Oil and Natural
Gas Sales $1,186,383 $772,401 $2,697,204 $1,311,343
Average Sales Price
(excluding gains (losses)
on derivatives):
Oil ($ per bbl) $64.51 $48.11 $61.73 $47.03
Natural gas ($ per mcf) $5.96 $6.29 $6.75 $6.00
Natural gas equivalent
($ per mcfe) $6.40 $6.47 $7.08 $6.19
Average Sales Price
(excluding unrealized gains
(losses) on derivatives):
Oil ($ per bbl) $58.80 $42.82 $57.97 $42.32
Natural gas ($ per mcf) $8.04 $5.95 $8.81 $6.07
Natural gas equivalent
($ per mcfe) $8.20 $6.08 $8.89 $6.17
Interest Expense
($ in thousands)
Interest $73,834 $54,710 $146,732 $102,003
Derivatives - realized
(gains) losses
(1,163) (675) (2,407) (1,796)
Derivatives - unrealized
(gains) losses 785 (133) 1,789 (3,177)
Total Interest Expense $73,456 $53,902 $146,114 $97,030
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
(in 000's)
(unaudited)
THREE MONTHS ENDED: June 30, June 30,
2006 2005
Cash provided by operating activities $ 1,077,686 $ 507,232
Cash (used in) investing activities (1,823,996) (1,365,941)
Cash provided by financing activities 1,074,294 858,709
SIX MONTHS ENDED: June 30, June 30,
2006 2005
Cash provided by operating activities $ 2,045,144 $ 1,019,917
Cash (used in) investing activities (3,784,057) (2,539,878)
Cash provided by financing activities 2,045,156 1,513,065
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
(in 000's)
(unaudited)
THREE MONTHS ENDED: June 30, March 31, June 30,
2006 2006 2005
CASH PROVIDED BY OPERATING ACTIVITIES $1,077,686 $ 967,458 $507,232
Adjustments:
Changes in assets and liabilities (163,520) 79,405 (53,498)
OPERATING CASH FLOW* $ 914,166 $1,046,863 $453,734
* 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.
THREE MONTHS ENDED: June 30, March 31, June 30,
2006 2006 2005
NET INCOME $ 359,903 $ 623,723 $193,779
Income tax expense 244,779 382,283 111,387
Interest expense 73,456 72,658 53,902
Depreciation and amortization
of other assets 23,163 23,872 11,807
Oil and natural gas depreciation,
depletion and amortization 328,159 304,957 209,371
EBITDA** $1,029,460 $1,407,493 $580,246
** 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:
THREE MONTHS ENDED: June 30, March 31, June 30,
2006 2006 2005
CASH PROVIDED BY OPERATING
ACTIVITIES $1,077,686 $967,458 $507,232
Changes in assets and liabilities (163,520) 79,405 (53,498)
Interest expense 73,456 72,658 53,902
Unrealized gains (losses) on oil
and natural gas derivatives 16,460 197,615 84,054
Other non-cash items 25,378 90,357 (11,444)
EBITDA $1,029,460 $1,407,493 $580,246
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
(in 000's)
(unaudited)
SIX MONTHS ENDED: June 30, June 30,
2006 2005
CASH PROVIDED BY OPERATING ACTIVITIES $2,045,144 $1,019,917
Adjustments:
Changes in assets and liabilities (84,115) (61,561)
OPERATING CASH FLOW* $1,961,029 $958,356
* 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.
SIX MONTHS ENDED: June 30, June 30,
2006 2005
NET INCOME $983,626 $318,789
Income tax expense 627,062 183,243
Interest expense 146,114 97,030
Depreciation and amortization of other assets 47,035 21,889
Oil and natural gas depreciation, depletion
and amortization 633,116 390,339
EBITDA** $2,436,953 $1,011,290
** 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:
SIX MONTHS ENDED: June 30, June 30,
2006 2005
CASH PROVIDED BY OPERATING ACTIVITIES $2,045,144 $1,019,917
Changes in assets and liabilities (84,115) (61,561)
Interest expense 146,114 97,030
Unrealized gains (losses) on oil
and natural gas derivatives 214,075 (33,073)
Other non-cash items 115,735 (11,023)
EBITDA $2,436,953 $1,011,290
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
($ in 000's, except per share amounts)
(unaudited)
June 30, March 31, June 30,
THREE MONTHS ENDED: 2006 2006 2005
Net income available
to common shareholders $ 332,128 $ 603,902 $ 179,177
Adjustments:
Loss on conversion/exchange
of preferred stock 9,547 1,009 4,743
Unrealized (gains) losses
on derivatives, net of tax (9,720) (121,899) (53,458)
Cumulative impact of new Texas
margin tax 15,000 --- ---
Reversal of severance tax accrual,
net of tax (7,192) --- ---
Gain on sale of investment,
net of tax --- (72,786) ---
Employee retirement expense,
net of tax --- 33,947 ---
Loss on repurchases or exchanges
of debt, net of tax --- --- 43,434
Adjusted net income available
to common shareholders* 339,763 444,173 173,896
Preferred dividends 18,228 18,812 9,859
Total adjusted net income $ 357,991 $ 462,985 $ 183,755
Weighted average fully diluted
shares outstanding** 434,915 431,723 366,677
Adjusted earnings per share
assuming dilution $ 0.82 $ 1.07 $ 0.50
* 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.
** 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)
June 30, March 31, June 30,
THREE MONTHS ENDED: 2006 2006 2005
EBITDA $ 1,029,460 $ 1,407,493 $ 580,246
Adjustments, before tax:
Unrealized (gains) losses on oil
and natural gas derivatives (16,460) (197,615) (84,054)
Reversal of severance tax accrual (11,600) --- ---
Gain on sale of investment --- (117,396) ---
Employee retirement expense --- 54,753 ---
Loss on repurchases or exchanges
of debt --- --- 68,400
Adjusted EBITDA* $ 1,001,400 $ 1,147,235 $ 564,592
* 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 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.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
($ in 000's, except per share amounts)
(unaudited)
June 30, June 30,
SIX MONTHS ENDED: 2006 2005
Net income available to common shareholders $ 936,030 $ 298,724
Adjustments:
Loss on conversion/exchange of preferred stock 10,556 4,743
Unrealized (gains) losses on derivatives,
net of tax (131,619) 18,985
Cumulative impact of new Texas margin tax 15,000 ---
Reversal of severance tax accrual, net of tax (7,192) ---
Gain on sale of investment, net of tax (72,786) ---
Employee retirement expense, net of tax 33,947 ---
Loss on repurchases or exchanges of debt,
net of tax --- 44,006
Adjusted net income available
to common shareholders* 783,936 366,458
Preferred dividends 37,040 15,322
Total adjusted net income $ 820,976 $ 381,780
Weighted average fully diluted shares outstanding** 433,414 359,136
Adjusted earnings per share assuming dilution $ 1.89 $ 1.06
* 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.
** 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)
June 30, June 30,
SIX MONTHS ENDED: 2006 2005
EBITDA $ 2,436,953 $ 1,011,290
Adjustments, before tax:
Unrealized (gains) losses on oil
and natural gas derivatives (214,075) 33,073
Reversal of severance tax accrual (11,600) ---
Gain on sale of investment (117,396) ---
Employee retirement expense 54,753 ---
Loss on repurchases or exchanges of debt --- 69,300
Adjusted EBITDA* $ 2,148,635 $ 1,113,663
*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 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.
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF JULY 27, 2006
Quarter Ending September 30, 2006; Year Ending December 31, 2006; Year Ending
December 31, 2007.
We have adopted a policy of periodically providing investors with guidance
on certain factors that affect our future financial performance. As of
July 27, 2006, we are using the following key assumptions in our projections
for the third quarter of 2006, the full-year 2006 and the full-year 2007.
The primary changes from our June 5, 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;
2) Production, certain costs and capital expenditure assumptions have
been updated;
3) We have shown our projections for the quarter ending September 30,
2006 for the first time.
Quarter Ending Year Ending Year Ending
9/30/2006 12/31/2006 12/31/2007
Estimated Production (A):
Oil - mbbls 2,000 8,400 8,400
Natural gas - bcf 136 - 140 531 - 541 595 - 605
Natural gas
equivalent - bcfe 148 - 152 581 - 591 645 - 655
Daily natural gas
equivalent midpoint
- in mmcfe 1,630 1,605 1,781
NYMEX Prices (B) (for
calculation of realized
hedging effects only):
Oil - $/bbl $56.25 $61.67 $56.25
Natural gas - $/mcf $6.96 $7.57 $7.50
Estimated Realized Hedging
Effects (based on assumed
NYMEX prices above):
Oil - $/bbl $7.26 $1.92 $11.43
Natural gas - $/mcf $1.89 $1.99 $1.89
Estimated Differentials
to NYMEX Prices:
Oil - $/bbl 6 - 8% 7 - 9% 6 - 8%
Natural gas - $/mcf 8 - 12% 10 - 15% 9 - 13%
Operating Costs per Mcfe
of Projected Production:
Production expense $0.85-0.95 $0.85-0.95 $0.90-1.00
Production taxes
(generally 6.0% of
O&G revenues) (C) $0.38-0.42 $0.41-0.46 $0.41-0.46
General and
administrative $0.15-0.20 $0.15-0.20 $0.15-0.20
Stock-based compensation
(non-cash) $0.05-0.07 $0.06-0.08 $0.08-0.10
DD&A of oil and natural
gas assets $2.35-2.40 $2.30-2.40 $2.40-2.50
Depreciation of
other assets $0.18-0.22 $0.18-0.22 $0.24-0.28
Interest expense (D) $0.55-0.59 $0.54-0.58 $0.60-0.65
Other Income per Mcfe:
Marketing and
other income $0.02-0.04 $0.04-0.06 $0.04-0.06
Service operations
income $0.10-0.12 $0.08-0.12 $0.10-0.15
Book Tax Rate (approximately
equal to 95% deferred) 38% 38% 38%
Equivalent Shares Outstanding:
Basic 418 mm 397 mm 423 mm
Diluted 484 mm 459 mm 488 mm
Capital Expenditures:
Drilling, leasehold
and seismic $900-1,100 mm $3,700-4,000 mm $3,800-4,100 mm
(A) Production forecast for Q3 2006 and calendar 2006 excludes
provisions for possible production curtailments that the industry
and Chesapeake may experience as a result of high pipeline pressures
and/or early filling of U.S. natural gas storage facilities.
(B) Oil NYMEX prices have been updated for actual contract prices
through June 2006 and natural gas NYMEX prices have been updated for
actual contract prices through July 2006.
(C) Severance tax per mcfe is based on NYMEX prices of $56.25 per bbl of
oil and $6.80 to $7.60 per mcf of natural gas during Q3 2006, $57.35
per bbl of oil and $7.50 to $8.50 per mcf of natural gas during
calendar 2006 and $56.25 per bbl of oil and $7.50 to $8.50 per mcf
of natural gas during calendar 2007.
(D) 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 loses 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 natural gas
swaps in place:
% Hedged
Open Swap
Positions
Avg. NYMEX as a % of
Price Estimated
Avg. NYMEX Including Assuming Total
Strike Price Gain (Loss) Open & Natural Gas Natural
Open Swaps Of Open from Locked Locked Production Gas
in Bcf's Swaps Swaps Positions in Bcf's of: Production
2006:
Q1 93.8 $10.81 -$0.09 $10.72 124.1 76%
Q2 101.4 $8.82 -$0.05 $8.77 129.8 78%
Q3 117.9 $8.80 -$0.05 $8.75 138.0 85%
Q4 114.9 $9.46 -$0.04 $9.42 144.1 80%
Total
2006(A) 428.0 $9.42 -$0.05 $9.37 536.0 80%
Total
2007 392.1 $9.99 -$0.03 $9.96 600.0 65%
Total
2008 329.4 $9.53 --- $9.53 642.0 51%
Total
2009 3.7 $9.02 --- $9.02 687.0 1%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 43.0 bcf in 2006, $5.75 to
$6.50 covering 53.9 bcf in 2007 and $5.75 to $6.50 covering 69.5 bcf
in 2008, respectively.
Note: Not shown above are collars covering 0.2 bcf of production in 2006
at a weighted average floor and ceiling of $6.00 and $9.70 and call options
covering 7.3 bcf of production in 2006 at a weighted average price of $12.50,
25.6 bcf of production in 2007 at a weighted average price of $10.53 and
7.3 bcf of production in 2008 at a weighed average price of $12.50.
The company has the following natural gas basis protection swaps in place:
Mid-Continent Appalachia
Volume in Bcf's NYMEX less*: Volume in Bcf's NYMEX plus*:
2006 130.1 $0.32 --- $---
2007 137.2 0.33 36.5 0.35
2008 118.6 0.27 36.6 0.35
2009 86.6 0.29 18.2 0.31
Totals 472.5 $0.30 91.3 $0.34
* 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 ($469 million as of
June 30, 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 derivative instruments assumed in connection with the
CNR acquisition 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:
% Hedged
Open Swap
Avg. NYMEX Avg. Fair Positions
Strike Value Upon as a %
Price Acquisition Initial Assuming of Estimated
Of Open of Open Liability Natural Gas Total
Open Swaps Swaps Swaps Acquired Production Natural Gas
in Bcf's (per Mcf) (per Mcf) (per Mcf) in Bcf's of: Production
2006:
Q1 7.9 $4.91 $12.14 ($7.23) 124.1 6%
Q2 10.5 $4.86 $9.97 ($5.11) 129.8 8%
Q3 10.6 $4.86 $9.95 ($5.09) 138.0 8%
Q4 10.6 $4.86 $10.38 ($5.52) 144.1 7%
Total
2006 39.6 $4.87 $10.51 ($5.64) 536.0 7%
Total
2007 42.0 $4.82 $9.18 ($4.36) 600.0 7%
Total
2008 38.4 $4.67 $8.01 ($3.34) 642.0 6%
Total
2009 18.3 $5.18 $7.28 ($2.10) 687.0 3%
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, respectively.
The company also has the following crude oil swaps in place:
% Hedged
Open Swap
Positions
Avg. Assuming Oil as % of Total
Open Swaps NYMEX Production Estimated
in mbbls Strike Price in mbbls of: Production
2006:
Q1 1,109.5 $60.03 2,116 52%
Q2 1,379.5 $61.85 2,143 64%
Q3 1,747.0 $64.83 2,000 87%
Q4 1,840.0 $65.64 2,141 86%
Total
2006(A) 6,076.0 $63.52 8,400 72%
Total
2007 6,110.0 $71.42 8,400 73%
Total
2008 5,032.0 $71.45 8,000 63%
Total
2009 182.5 $66.10 8,000 2%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $40.00 to $60.00 covering 654.5 mbbls in 2006, $45.00
to $60.00 covering 1,460.0 mbbls in 2007 and $45.00 to $60.00
covering 1,098.0 mbbls in 2008, respectively.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF JUNE 5, 2006
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF JULY 27, 2006
Quarter Ending June 30, 2006; Year Ending December 31, 2006; Year Ending
December 31, 2007.
We have adopted a policy of periodically providing investors with guidance
on certain factors that affect our future financial performance. As of
June 5, 2006, we are using the following key assumptions in our projections
for the second quarter of 2006, the full-year 2006 and the full-year 2007.
The primary changes from our May 1, 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;
2) Production, certain costs and capital expenditures have increased as a
result of the acquisitions announced today; and
3) Share count has been adjusted to reflect our tender offer to convert
our 4.125% preferred stock and 5.0% preferred stock to common stock,
recent repurchases of common stock and an expected preferred equity
offering in the near future.
Quarter Ending Year Ending Year Ending
6/30/2006 12/31/2006 12/31/2007
Estimated Production:
Oil - mbbls 2,000 8,000 8,000
Natural gas - bcf 127 - 132 533 - 543 592 - 602
Natural gas equivalent - bcfe 139 - 144 581 - 591 640 - 650
Daily natural gas equivalent
midpoint -in mmcfe 1,555 1,605 1,767
NYMEX Prices(A) (for
calculation of realized
hedging effects only):
Oil - $/bbl $58.39 $56.72 $52.50
Natural gas - $/mcf $7.16 $7.54 $7.00
Estimated Realized Hedging
Effects (based on assumed
NYMEX prices above):
Oil - $/bbl $2.62 $4.83 $9.39
Natural gas - $/mcf $1.68 $2.00 $2.19
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 $0.85 - 0.95 $0.90 - 1.00
Production taxes
(generally 6.0% of
O&G revenues)(B) $0.40 - 0.45 $0.41 - 0.46 $0.36 - 0.41
General and administrative $0.15 - 0.20 $0.15 - 0.20 $0.15 - 0.20
Stock-based compensation
(non-cash) $0.05 - 0.07 $0.06 - 0.08 $0.08 - 0.10
DD&A of oil and natural
gas assets $2.25 - 2.35 $2.30 - 2.40 $2.40 - 2.50
Depreciation of other
assets $0.16 - 0.20 $0.18 - 0.22 $0.24 - 0.28
Interest expense(C) $0.52 - 0.57 $0.52 - 0.57 $0.53 - 0.58
Other Income per Mcfe:
Marketing and other income $0.02 - 0.04 $0.04 - 0.06 $0.04 - 0.06
Service operations income $0.10 - 0.15 $0.10 - 0.15 $0.10 - 0.15
Book Tax Rate (approximately
95% deferred) 37.5% 37.5% 37.5%
Equivalent Shares Outstanding:
Basic 379 mm 380 mm 389 mm
Diluted 434 mm 441 mm 452 mm
Capital Expenditures:
Drilling, leasehold
and seismic $900-1,000 $3,500-3,800 $3,500-3,800
mm mm mm
(A) Oil NYMEX prices have been updated for actual contract prices through
April 2006 and natural gas NYMEX prices have been updated for actual
contract prices through May 2006.
(B) Severance tax per mcfe is based on NYMEX prices of $58.39 per bbl of
oil and $7.20 to $8.20 per mcf of natural gas during Q2 2006, $56.72
per bbl of oil and $7.35 to $8.35 per mcf of natural gas during
calendar 2006, and $52.50 per bbl of oil and $6.50 to $7.50 per mcf of
natural gas during calendar 2007.
(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 natural gas
swaps in place:
% Hedged
Open Swap
Positions
Avg. NYMEX as a % of
Price Estimated
Avg. NYMEX Including Assuming Total
Strike Price Gain (Loss) Open & Natural Gas Natural
Open Swaps Of Open from Locked Locked Production Gas
in Bcf's Swaps Swaps Positions in Bcf's of: Production
2006:
Q1 93.8 $10.81 -$0.09 $10.72 124.1 76%
Q2 101.4 $8.82 -$0.05 $8.77 129.5 78%
Q3 117.9 $8.80 -$0.05 $8.75 138.5 85%
Q4 114.9 $9.46 -$0.04 $9.42 145.9 79%
Total
2006(A) 428.0 $9.42 -$0.05 $9.37 538.0 80%
Total
2007(A) 370.2 $9.98 -$0.04 $9.94 597.0 62%
Total
2008(A) 311.1 $9.50 --- $9.50 637.0 49%
Total
2009 3.7 $9.02 --- $9.02 682.0 1%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 43.0 bcf in 2006, $5.75 to
$6.50 covering 32.0 bcf in 2007 and $5.75 to $6.50 covering 51.2 bcf
in 2008, respectively.
Note: Not shown above are collars covering 0.2 bcf of production in 2006
at a weighted average floor and ceiling of $6.00 and $9.70 and call options
covering 7.3 bcf of production in 2006 at a weighted average price of $12.50,
25.6 bcf of production in 2007 at a weighted average price of $10.53 and 7.3
bcf of production in 2008 at a weighed average price of $12.50.
The company has the following natural gas basis protection swaps in place:
Mid-Continent Appalachia
Volume in Bcf's NYMEX less*: Volume in Bcf's NYMEX plus*:
2006 130.1 $0.32 --- $---
2007 137.2 0.33 36.5 0.35
2008 118.6 0.27 36.6 0.35
2009 86.6 0.29 18.2 0.31
Totals 472.5 $0.30 91.3 $0.34
* weighted average
We assumed certain liabilities related to open derivative positions in
connection with the CNR acquisition. In accordance with SFAS 141, these
derivative positions were recorded at fair value in the purchase price
allocation as a liability of $592 million ($523 million as of March 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 derivative instruments assumed in connection with the
CNR acquisition 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:
% Hedged
Open Swap
Avg. NYMEX Avg. Fair Positions
Strike Value Upon as a %
Price Acquisition Initial Assuming of Estimated
Of Open of Open Liability Natural Gas Total
Open Swaps Swaps Swaps Acquired Production Natural Gas
in Bcf's (per Mcf) (per Mcf) (per Mcf) in Bcf's of: Production
2006:
Q1 7.9 $4.91 $12.14 ($7.23) 124.1 6%
Q2 10.5 $4.86 $9.97 ($5.11) 129.5 8%
Q3 10.6 $4.86 $9.95 ($5.09) 138.5 8%
Q4 10.6 $4.86 $10.38 ($5.52) 145.9 7%
Total
2006 39.6 $4.87 $10.51 ($5.64) 538.0 7%
Total
2007 42.0 $4.82 $9.18 ($4.36) 597.0 7%
Total
2008 38.4 $4.67 $8.01 ($3.34) 637.0 6%
Total
2009 18.3 $5.18 $7.28 ($2.10) 682.0 3%
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, respectively.
The company also has the following crude oil swaps in place:
% Hedged
Open Swap
Positions
Avg. Assuming Oil as % of Total
Open Swaps NYMEX Production Estimated
in mbbls Strike Price in mbbls of: Production
2006:
Q1 1,109.5 $60.03 2,116 52%
Q2 1,379.5 $61.85 2,000 69%
Q3 1,625.0 $63.90 1,942 84%
Q4 1,656.0 $63.76 1,942 85%
Total
2006(A) 5,770.0 $62.63 8,000 72%
Total
2007 4,452.0 $68.79 8,000 56%
Total
2008 3,843.0 $69.50 8,000 48%
Total
2009 182.5 $66.26 8,000 2%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $40.00 to $42.00 covering 501.5 mbbls in 2006, $45.00
covering 182.5 mbbls in 2007 and $45.00 covering 183.0 mbbls in
2008, respectively.
SOURCE Chesapeake Energy Corporation