Company Reports 2005 Second Quarter Net Income Available to Common
Shareholders of $179 Million on Revenue of $1.05 Billion and Production of
113 Bcfe
Oil and Natural Gas Production Reaches 1,244 Mmcfe per Day, a 31% Increase
Over 2004 Second Quarter and 7% Over 2005 First Quarter; 2005 Total Production
Growth Expected to Exceed 25%, 2005 Organic Growth Expected to Exceed 10%
Proved Reserves Reach 5.9 Tcfe and Non-Proven Reserves Exceed 5.0 Tcfe; First
Half 2005 Proved Reserve Adds Total 948 Bcfe; Reserve Replacement Equals 535%
at Drilling and Acquisition Cost of $1.49 Per Mcfe
Company Acquires 294 Bcfe of Proved, Probable and Possible Reserves and
33 Mmcfe of Current Daily Production for $410 Million in Four Transactions
With Private Companies
OKLAHOMA CITY, Aug. 4 /PRNewswire-FirstCall/ -- Chesapeake Energy
Corporation (NYSE: CHK) today reported financial and operating results for the
second quarter of 2005. For the quarter, Chesapeake generated net income
available to common shareholders of $179.2 million ($0.52 per fully diluted
common share), operating cash flow of $513.3 million (defined as cash flow
from operating activities before changes in assets and liabilities) and ebitda
of $580.2 million (defined as income before income taxes, interest expense,
and depreciation, depletion and amortization expense) on revenue of $1,048.0
million and production of 113.2 billion cubic feet of natural gas equivalent
(bcfe).
The company's 2005 second quarter net income available to common
shareholders and ebitda include certain items that are not typically included
in published estimates of the company's financial results by many securities
analysts. Such items and their after-tax effects on second quarter reported
results are described as follows:
* an unrealized mark-to-market gain of $53.4 million resulting from the
company's oil, natural gas and interest rate hedging programs;
* a $43.4 million loss resulting from the early extinguishment of
certain Chesapeake debt securities; and
* a reduction of net income available to common shareholders of
$4.7 million resulting from a loss on the exchange of approximately
$45 million of Chesapeake's 4.125% cumulative convertible preferred
stock into 2.9 million shares of the company's common stock through an
unsolicited transaction with a holder of the preferred stock.
Adjusted for the above-mentioned items, Chesapeake's net income to common
shareholders in the 2005 second quarter would have been $173.9 million ($0.50
per fully diluted common share) and ebitda would have been $564.6 million. The
foregoing items do not affect the calculation of operating cash flow. A
reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted
net income available to common to comparable financial measures calculated in
accordance with generally accepted accounting principles is presented on pages
15-17 of this release.
Oil and Natural Gas Production Sets Record for 16th Consecutive Quarter;
2005 Second Quarter Average Daily Production Increases 31% Over
2004 Second Quarter and 7% Over 2005 First Quarter
Daily production for the 2005 second quarter averaged 1,244 million cubic
feet of natural gas equivalent (mmcfe), an increase of 293 mmcfe, or 30.8%,
over the 951 mmcfe produced per day in the 2004 second quarter and an increase
of 82 mmcfe, or 7.1%, over the 1,162 mmcfe produced per day in the 2005 first
quarter. Of the 82 mmcfe daily increase in sequential quarterly production,
37% came from organic growth and 63% from acquisition growth, making the
company's quarterly organic growth rate 2.7%, its year-to-date organic growth
rate 5.1% and its annualized 2005 organic growth rate 10.2%. The company's
2005 second quarter production exceeded its May 2, 2005 forecasted mid-point
production by 3.7 bcfe, or 3.4%, because of stronger than projected drilling
and operational results.
Chesapeake's 2005 second quarter production of 113.2 bcfe was comprised of
101.1 billion cubic feet of natural gas (bcf) (89% on a natural gas equivalent
basis) and 2.01 million barrels of oil and natural gas liquids (mmbo) (11% on
a natural gas equivalent basis). Chesapeake's average daily production rate
of 1,244 mmcfe consisted of 1,111 mmcf of gas and 22,110 barrels of oil and
natural gas liquids.
The 2005 second quarter was Chesapeake's 16th consecutive quarter of
production growth. During these 16 quarters, Chesapeake's U.S. production has
increased 214%, for an average compound quarterly growth rate of 7.4% and an
average compound annual growth rate of 33.1%.
Key Operational and Financial Statistics are Summarized Below
for the 2005 Second and First Quarters and the 2004 Second Quarter
The table below summarizes Chesapeake's key results during the 2005 second
quarter and compares them to results from the 2005 first quarter and the 2004
second quarter:
Three Months Ended
6/30/05 3/31/05 6/30/04
Average daily production (in mmcfe) 1,244 1,162 951
Gas as % of total production 89 90 88
Natural gas production (in bcf) 101.1 94.1 76.5
Average realized gas price ($/mcf) (A) 5.95 6.20 4.87
Oil production (in mbbls) 2,012 1,746 1,673
Average realized oil price ($/bo) (A) 42.82 41.74 28.12
Natural gas equivalent production (in bcfe) 113.2 104.6 86.5
Gas equivalent realized price ($/mcfe) (A) 6.08 6.27 4.85
Net marketing income ($/mcfe) .05 .07 .04
General and administrative costs ($/mcfe) (B) (.08) (.09) (.09)
Stock-based compensation ($/mcfe) (.02) (.02) (.00)
Production taxes ($/mcfe) (.42) (.34) (.26)
Production expenses ($/mcfe) (.64) (.66) (.57)
Interest expense ($/mcfe) (A) (.48) (.44) (.44)
DD&A of oil and gas properties ($/mcfe) (1.85) (1.73) (1.58)
D & A of other assets ($/mcfe) (.10) (.10) (.08)
Operating cash flow ($ in millions) (C) 513.3 505.5 308.2
Operating cash flow ($/mcfe) 4.53 4.83 3.56
Ebitda ($ in millions) (D) 580.2 431.0 324.1
Ebitda ($/mcfe) 5.13 4.12 3.74
Net income to common shareholders
($ in millions) 179.2 119.5 85.8
(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 income before income taxes, interest expense, and
depreciation, depletion and amortization expense
Chesapeake Announces $410 Million of Acquisitions in the Barnett Shale, East
Texas and Permian Basin Areas; Acquires 294 Bcfe of Proved, Probable and
Possible (3P) Reserves and 33 Mmcfe of Current Daily Production
Subsequent to the end of the 2005 second quarter, Chesapeake has acquired
or has agreed to acquire $410 million of natural gas assets in transactions
with four private companies. Through these transactions, the company will
acquire 33 mmcfe per day of current production, 113 bcfe of proved reserves
and 181 bcfe of probable and possible reserves. After allocating $15 million
of the purchase prices to gas gathering and compression assets and after
including $368 million of future development costs, Chesapeake's estimated
all-in acquisition cost for the 294 bcfe of 3P reserves will be $2.60 per
thousand cubic feet of natural gas equivalent (mcfe).
The largest of the four acquisitions is Chesapeake's recently closed
purchase of Hallwood Energy III L.P.'s 56% working interest in the 30,000
gross acre Chesapeake/Hallwood South Block AMI in Johnson County, Texas.
Chesapeake had previously acquired a 44% working interest in the AMI area
through its acquisition of Oklahoma City-based publicly-held Canaan Energy
Corporation in June 2002.
In the South Block transaction, Chesapeake anticipates acquiring an
internally estimated 174 bcfe of 3P reserves and current net production of
14 mmcfe per day. The company has identified 160 horizontal drilling
locations on the 30,000 gross acre South Block that it believes can be drilled
at an average cost of approximately $2.5 million per well to develop average
estimated ultimate reserves (EUR) of approximately 2.0 bcfe per well. The
company currently has two rigs drilling on this South Block acreage.
Including production from both the North and South Block acreage, Chesapeake's
current Barnett Shale average daily production is approximately 50 mmcfe and
should average at least 80 and 120 mmcfe per day by December 2005 and December
2006, respectively.
The South Block proved reserves have a reserves-to-production index of
7.9 years, are 100% gas, have current lease operating expenses of $0.20 per
mcfe, have severance taxes of less than 1.0% of the wellhead revenue value and
are 100% Chesapeake-operated. The property's very low lease operating expenses
(approximately $0.55 per mcfe below the industry average) and unusually low
severance taxes (approximately $0.50 below the standard 7.5% Texas severance
tax rate at $7.00 per mcf because of severance tax exemptions applicable to
certain types of newly drilled wells in Texas) create an approximate $1.05 per
mcfe economic advantage over typical acquisitions of other Texas or Mid-
Continent natural gas properties. The company has hedged 100% of its newly
acquired Hallwood production volumes at an average NYMEX gas price of $8.53
per mmbtu through March 31, 2006, well above the gas price used to value the
property.
By comparison, in December 2004 when Chesapeake acquired its North Block
acreage for $277 million, Chesapeake acquired 25 mmcfe of daily production and
3P reserves of 280 bcfe. The company projected that its all-in finding costs
to develop the 3P reserves would be $2.07 per mcfe and it hedged the first two
years of production at an average price of $6.89 per mmbtu.
Subsequent to closing the North Block acquisition, Chesapeake has invested
$35 million in the drilling of 21 wells and has received $21 million of
operating cash flow from production of 4.8 bcfe. Current production and
proved reserves have increased 36% and 24%, respectively, in just eight
months. Finding costs have been $1.12 per mcfe since the date of acquisition.
Average well costs have been $2.4 million and per well reserves have been
2.8 bcfe compared to the company's estimates at the time of acquisition of
$2.2 million and 2.5 bcfe. Chesapeake currently has four rigs drilling on the
North Block and believes that it has approximately 135 more horizontal wells
to drill on the North Block.
In addition to the Hallwood South Block acquisition, Chesapeake has also
recently acquired or agreed to acquire an additional $160 million of natural
gas properties in the East Texas and Permian Basin regions in three
transactions with three private companies. In these acquisitions, Chesapeake
is acquiring 19 mmcfe per day of net production and 120 bcfe of 3P reserves.
The proved reserves acquired in the three miscellaneous transactions have a
reserves-to-production index of 10.2 years, are 99% gas, have current lease
operating expenses of approximately $0.20 per mcfe and will be 98% Chesapeake-
operated.
The company has initially financed its recent acquisition activity with
funds drawn from its bank credit facility, but intends to permanently fund
these acquisitions with a combination of equity and/or long-term senior
unsecured notes issuance in the near future.
Average Prices Realized, Hedging Positions Updated and Production Forecasts
for Second Half 2005 and Full Year 2006 Increased
Average prices realized during the 2005 second quarter (including realized
gains or losses from oil and gas derivatives, but excluding unrealized gains
or losses on such derivatives) were $42.82 per bo and $5.95 per mcf, for a
realized gas equivalent price of $6.08 per mcfe. Chesapeake's average
realized pricing differentials to NYMEX during the second quarter were a
negative $4.78 per bo and a negative $0.65 per mcf. Realized losses from oil
and natural gas hedging activities during the quarter generated a $5.29 loss
per bo and a $0.34 loss per mcf, for a 2005 second quarter realized hedging
loss of $44.4 million, or $0.39 per mcfe. This compares to a 2005 first
quarter realized hedging gain of $40.3 million, or $0.39 per mcfe, and a 2004
second quarter realized hedging loss of $55.3 million, or $0.64 per mcfe.
Chesapeake has added to its 2005, 2006 and 2007 oil and natural gas hedge
positions previously provided on May 2, 2005. The following tables compare
Chesapeake's hedged production volumes through swaps as of August 4, 2005 to
those as of May 2, 2005:
Swap Positions as of August 4, 2005
Oil Natural Gas
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2005 3Q 46% $51.41 67% $6.46
2005 4Q 48% $52.99 52% $6.89
2005 Remaining 47% $52.22 59% $6.65
2006 37% $56.75 27% $7.23
2007 8% $53.33 2% $7.06
Swap Positions as of May 2, 2005
Oil Natural Gas
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2005 3Q 35% $48.46 57% $6.28
2005 4Q 30% $48.46 38% $6.46
2005 Remaining 32% $48.46 47% $6.35
2006 16% $54.77 18% $6.85
2007 5% $50.79 --- ---
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 2005 and 2006 forecasts are attached to this release
in an Outlook dated August 4, 2005 labeled as Schedule "A". This Outlook has
been changed from the Outlook dated May 2, 2005 (attached as Schedule "B" for
investors' convenience) to reflect updated information resulting from the
company's operational performance during the second quarter exceeding
forecasted results and from the Hallwood and three miscellaneous acquisitions
announced today.
Production estimates for 2005 were increased by 2.4%, or 30 mmcfe per day,
to estimated total production of 460 bcfe for the year, or a daily average of
1,260 mmcfe. Production estimates for 2006 were increased by 2.0%, or 28 mmcfe
per day, to estimated total production of 516 bcfe for the year, or a daily
average of 1,414 mmcfe per day. This marks the 21st time that Chesapeake has
increased its production estimates during the past 16 quarters.
Oil and Natural Gas Proved Reserves Reach Record Level of 5.9 Tcfe;
First Half 2005 Drilling and Acquisition Costs are $1.49 per Mcfe
as Company Adds 948 Bcfe and Replaces Production by 535%
Chesapeake began 2005 with estimated proved reserves of 4.902 trillion
cubic feet of natural gas equivalent (tcfe) and ended the second quarter with
5.850 tcfe, an increase of 948 bcfe, or 19%. During the 2005 first half, the
company replaced its 218 bcfe of production with an estimated 1,166 bcfe of
new proved reserves, for a reserve replacement rate of 535% at a drilling and
acquisition cost of $1.49 per mcfe. Reserve replacement through the drillbit
was 583 bcfe, or 268% of production (including 43 bcfe from positive
performance revisions and 25 bcfe from oil and natural gas price increases),
or 50% of the total increase, at a cost of $1.46 per mcfe. Reserve
replacement through acquisitions was 583 bcfe, or 267% of production, or 50%
of the total increase, at a cost of $1.52 per mcfe. The above figures do not
include the impact of the Hallwood and the three miscellaneous acquisitions,
which closed or will close after the end of the 2005 second quarter.
Total costs incurred to acquire and develop proved reserves during the
first half of 2005 were $2.26 per mcfe, which includes drilling, completion,
acquisition, seismic, leasehold, capitalized internal costs, non-cash tax
basis step-up from various corporate acquisitions ($252 million, or $0.22 per
mcfe), asset retirement obligations and all other capitalized miscellaneous
costs. These costs exclude future development costs of proved undeveloped
reserves. A complete reconciliation of finding and acquisition cost
information and a roll forward of proved reserves is presented on page 13 of
this release.
As of June 30, 2005, the company's estimated future net cash flows
discounted at 10% before taxes (PV-10) from its proved reserves were
$14.6 billion using field differential adjusted prices of $52.35 per bo (based
on a NYMEX quarter-end price of $56.72 per bo) and $6.41 per mcf (based on a
NYMEX quarter-end price of $7.07 per mcf). Chesapeake's PV-10 changes by
approximately $255 million for every $0.10 per mcf change in gas prices and
approximately $48 million for every $1.00 per bo change in oil prices. The
above figures do not include the impact of the Hallwood and the three
miscellaneous acquisitions, which closed or will close after the end of the
2005 second quarter.
Company's Leasehold and 3-D Seismic Inventories Increase to 4.1 Million
and 10.8 Million Net Acres; Non-Proven Reserves on the Company's
Extensive Leasehold Now Exceed 5.0 Tcfe
Chesapeake's exploratory and development drilling programs and production
enhancement operations continue to produce operational results that exceed the
company's forecasts and distinguish the company among its peers. During the
2005 second quarter, Chesapeake drilled 224 gross (162 net) operated wells and
participated in another 296 gross (34 net) wells operated by other companies.
The company's drilling success rate was 97% for company-operated wells and 98%
for non-operated wells. During the quarter, Chesapeake invested $400 million
in operated wells (using an average of 73 operated rigs), $77 million in non-
operated wells (using an average of approximately 65 non-operated rigs) and
$105 million in acquiring new 3-D seismic data and new leasehold (excluding
leasehold acquired through acquisitions).
During the past five years, Chesapeake has built what it believes to be
the largest inventories of onshore leasehold (4.1 million acres) and 3-D
seismic (10.8 million acres) in the U.S. On this leasehold, the company has
identified more than an nine-year inventory of 14,000 drillsites on which it
believes it can develop approximately 2.2 tcfe of proved undeveloped reserves
and more than 5.0 tcfe of non-proven reserves.
Chesapeake characterizes its drilling activity by one of three play types:
conventional, unconventional gas resource and emerging gas resource. The
company's approximate leasehold and proved undeveloped and non-proven reserve
totals are set forth below:
* 2.6 million net acres in its traditional conventional areas (i.e.,
much of the Mid-Continent, Permian, Gulf Coast, South Texas and other
areas) on which it has identified more than 3,200 drillsites, 1.0 tcfe
of proved undeveloped reserves and more than 1.4 tcfe of non-proven
reserves;
* 0.9 million net acres in its unconventional gas resource areas (i.e.,
Sahara, Granite/Cherokee/Atoka Washes, Hartshorne CBM, Barnett Shale
and Ark-La-Tex tight sands) on which it has identified more than
10,000 drillsites, 1.1 tcfe of proved undeveloped reserves and more
than 2.8 tcfe of non-proven reserves; and,
* 0.6 million net acres in its emerging gas resource areas (i.e.,
Fayetteville Shale, Caney/Woodford Shales, Haley Deep and others) on
which it has identified more than 900 drillsites, less than 0.1 tcfe
of proved undeveloped reserves and more than 0.8 tcfe of non-proven
reserves.
Chesapeake continues to actively acquire more acreage in all three play
types with more than 500,000 acres acquired in the 2005 second quarter through
an aggressive land acquisition program that continually utilizes more than
450 land brokers in the field researching land records and acquiring leases.
Chesapeake Continues to Increase Investments in Drilling Rigs and
Estimates Fair Value of its Drilling Rig Investments Exceeds
Cost Basis by $150 Million to Date
In 2003, Chesapeake began an aggressive program of hedging its exposure to
expected increases in service industry costs by initiating a program of
investing directly and indirectly in drilling rigs. To date, the company's
investments consist of the following:
* a 100% interest in Chesapeake's wholly owned drilling subsidiary,
Nomac Drilling Corporation. Nomac presently owns 14 rigs, all of
which are drilling Chesapeake-operated wells, and has an additional
18 rigs on order for delivery later in 2005 and in 2006. The
company's cost basis in its existing 14 rigs is $80 million and
Chesapeake believes Nomac's fair market value now exceeds $150
million.
* a 17% interest in Pioneer Drilling Corporation (Amex: PDC). This
interest was acquired in three separate transactions and has resulted
in Chesapeake investing $43 million to date in PDC for an average cost
basis of $5.55 per share. Based on PDC's closing stock price on
August 3 of $16.09, the company's unrealized gain to date on this
investment is $81 million. Pioneer owns 50 rigs and has an additional
7 rigs on order.
* a 45% interest in DHS Drilling Company, a Casper, Wyoming-based
drilling rig company which has four rigs operating in the Rocky
Mountains and which plans to expand to ten rigs over the next several
months. Chesapeake has invested $15 million in DHS to date.
* a 49% interest in Mountain Drilling Company, a newly formed venture
with a New York based investment banking firm in which Chesapeake and
its partner have each invested $25 million to secure four specialty
rigs for drilling in urban areas or in areas of special environmental
sensitivity.
In addition, the company is sponsoring the construction of approximately
another 20 rigs through various intermediate-term drilling contracts with
third party rig builders and operators. In total, Chesapeake believes its
$163 million of rig investments have appreciated in value by more than
$150 million and have or will increase the U.S. drilling rig fleet by
approximately 50 rigs from 2004 to 2006.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented,
"Today's announcement of very strong operational and financial results for the
2005 second quarter provides ongoing confirmation that Chesapeake's business
strategy continues to create significant shareholder value. This strategy has
generated a 75% increase in our common stock price during the past year and an
approximate 20-fold increase since our IPO in February 1993 through:
* delivering consistent and value-added growth through a balance of
acquisitions and exploratory and developmental drilling;
* focusing on natural gas to take advantage of strong long-term natural
gas supply/demand fundamentals; and
* building dominant regional scale to achieve low operating costs and
high returns.
"We believe Chesapeake's management team can continue the successful
execution of the company's distinctive business strategy and continue to
deliver significant shareholder value for years to come."
Conference Call Information
A conference call has been scheduled for Friday morning, August 5, 2005 at
9:00 a.m. EDT to discuss this earnings release. The telephone number to
access the conference call is 913.981.5592. For those unable to participate
in the conference call, a replay will be available from 12:00 noon EDT,
August 5, 2005 through midnight EDT on August 19, 2005. The number to access
the conference call replay is 719.457.0820 and the passcode is 2749019. The
conference call will also be simulcast live on the Internet and can be
accessed at http://www.chkenergy.com by selecting "Conference Calls" under the
"Investor Relations" section. The webcast of the conference call will be
available on the 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 gas reserves, expected oil and gas production and
future expenses, projections of future oil and 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 item 1 of our 2004 Annual Report
on Form 10-K filed with the Securities and Exchange Commission on March 9,
2005. They include the volatility of oil and gas prices; adverse effects our
level of indebtedness could have on our operations and future growth; our
ability to compete effectively against strong independent oil and gas
companies and majors; the availability of capital on an economic basis to fund
reserve replacement costs; uncertainties inherent in estimating quantities of
oil and gas reserves and projecting future rates of production and the timing
of development expenditures; our ability to replace reserves and sustain
production; uncertainties in evaluating oil and gas reserves of acquired
properties and associated potential liabilities; unsuccessful exploration and
development drilling; declines in the values of our oil and gas properties
resulting in ceiling test write-downs; lower prices realized on oil and gas
sales and collateral required to secure hedging liabilities resulting from our
commodity price risk management activities; 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. 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 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 "non-proven" 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 non-proven drillsites and estimation of non-proven reserves
have been appropriately risked and are reasonable, such calculations and
estimates have not been reviewed by third party engineers or appraisers.
The announcement of proposed financings through the issuance of equity
and/or senior notes in this press release shall not constitute an offer to
sell or a solicitation of an offer to buy the securities. The terms of any
such offerings have not been decided. The securities may not be registered
under the Securities Act of 1933 or any state securities laws and, if not
registered, may not be offered or sold in the United States absent
registration or an applicable exemption from the registration requirements of
the Securities Act and state laws.
Chesapeake Energy Corporation is the third 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 property
acquisitions in the Mid-Continent, Permian Basin, South Texas, Texas Gulf
Coast and Ark-La-Tex (including the Barnett Shale) 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 Three Months Ended
June 30, 2005 June 30, 2004
$ $/mcfe $ $/mcfe
REVENUES:
Oil and gas sales 772,401 6.83 399,665 4.62
Oil and gas marketing sales 275,617 2.43 174,627 2.02
Total Revenues 1,048,018 9.26 574,292 6.64
OPERATING COSTS:
Production expenses 72,333 0.64 49,595 0.57
Production taxes 47,253 0.42 22,751 0.26
General and administrative
expenses:
General and administrative
(excluding stock-based
compensation) 9,282 0.08 7,420 0.09
Stock-based compensation 2,506 0.02 672 0.01
Oil and gas marketing
expenses 270,003 2.39 171,115 1.98
Oil and gas depreciation,
depletion, and amortization 209,371 1.85 136,743 1.58
Depreciation and amortization
of other assets 11,807 0.10 6,716 0.08
Total Operating Costs 622,555 5.50 395,012 4.57
INCOME FROM OPERATIONS 425,463 3.76 179,280 2.07
OTHER INCOME (EXPENSE):
Interest and other income 2,005 0.02 1,335 0.01
Interest expense (53,902) (0.48) (28,806) (0.33)
Loss on repurchases or
exchanges of
Chesapeake debt (68,400) (0.60) --- ---
Total Other
Income (Expense) (120,297) (1.06) (27,471) (0.32)
Income Before Income Taxes 305,166 2.70 151,809 1.75
Income Tax Expense:
Current --- --- --- ---
Deferred 111,387 0.99 54,654 0.63
Total Income Tax Expense 111,387 0.99 54,654 0.63
NET INCOME 193,779 1.71 97,155 1.12
Preferred stock dividends (9,859) (0.09) (11,344) (0.13)
Loss on conversion/exchange
of preferred stock (4,743) (0.04) --- ---
NET INCOME AVAILABLE TO
COMMON SHAREHOLDERS 179,177 1.58 85,811 0.99
EARNINGS PER COMMON SHARE:
Basic $ 0.58 $ 0.36
Assuming dilution $ 0.52 $ 0.30
WEIGHTED AVERAGE COMMON
AND COMMON EQUIVALENT SHARES
OUTSTANDING (in 000's):
Basic 311,181 241,147
Assuming dilution 364,063 322,194
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
Six Months Ended Six Months Ended
June 30, 2005 June 30, 2004
$ $/mcfe $ $/mcfe
REVENUES:
Oil and gas sales 1,311,343 6.01 819,458 4.95
Oil and gas marketing sales 520,125 2.39 317,963 1.92
Total Revenues 1,831,468 8.40 1,137,421 6.87
OPERATING COSTS:
Production expenses 141,895 0.65 94,398 0.57
Production taxes 83,211 0.38 37,687 0.23
General and administrative
expenses:
General and administrative
(excluding stock-based
compensation) 18,932 0.09 15,586 0.09
Stock-based compensation 4,923 0.02 2,541 0.02
Oil and gas marketing expenses 507,279 2.33 310,779 1.87
Oil and gas depreciation,
depletion, and amortization 390,339 1.79 256,651 1.55
Depreciation and amortization
of other assets 21,889 0.10 12,455 0.08
Total Operating Costs 1,168,468 5.36 730,097 4.41
INCOME FROM OPERATIONS 663,000 3.04 407,324 2.46
OTHER INCOME (EXPENSE):
Interest and other income 5,362 0.02 2,678 0.02
Interest expense (97,030) (0.44) (75,351) (0.46)
Loss on repurchases or exchanges
of Chesapeake debt (69,300) (0.32) (6,925) (0.04)
Total Other Income
(Expense) (160,968) (0.74) (79,598) (0.48)
Income Before Income Taxes 502,032 2.30 327,726 1.98
Income Tax Expense:
Current --- --- --- ---
Deferred 183,243 0.84 117,981 0.71
Total Income Tax Expense 183,243 0.84 117,981 0.71
NET INCOME 318,789 1.46 209,745 1.27
Preferred stock dividends (15,322) (0.07) (19,512) (0.12)
Loss on conversion/exchange
of preferred stock (4,743) (0.02) --- ---
NET INCOME AVAILABLE TO COMMON
SHAREHOLDERS 298,724 1.37 190,233 1.15
EARNINGS PER COMMON SHARE:
Basic $0.96 $0.80
Assuming dilution $0.88 $0.67
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING
(in 000's):
Basic 310,523 239,016
Assuming dilution 356,478 310,937
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in 000's)
(unaudited)
June 30, December 31,
2005 2004
Cash $ --- $ 6,896
Other current assets 572,006 560,644
Total Current Assets 572,006 567,540
Property and equipment (net) 9,803,357 7,444,384
Other assets 282,523 232,585
Total Assets $10,657,886 $8,244,509
Current liabilities $ 1,165,844 $ 963,953
Long term debt 4,125,929 3,075,109
Asset retirement obligation 82,938 73,718
Other long term liabilities 70,270 34,973
Deferred tax liability 1,361,259 933,873
Total Liabilities 6,806,240 5,081,626
STOCKHOLDERS' EQUITY 3,851,646 3,162,883
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY $10,657,886 $8,244,509
COMMON SHARES OUTSTANDING 318,543 311,869
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF SIX MONTHS ENDED JUNE 30, 2005 COSTS INCURRED
($ in 000's, except per unit amounts)
(unaudited)
Reserves
Cost (in mmcfe) $/mcfe
Exploration and development
costs (A) $ 853,424 583,227 $ 1.46
Acquisition of proved properties 885,052 583,092 1.52
Subtotal 1,738,476 1,166,319 1.49
Acquisition of unproved properties 502,374 --- ---
Divestitures (114) (5) ---
Leasehold acquisition costs 90,976 --- ---
Geological and geophysical costs 26,620 --- ---
Adjusted subtotal 2,358,332 1,166,314 2.02
Tax basis step-up 251,659 --- ---
Asset retirement obligation
and other 21,996 --- ---
Total $2,631,987 1,166,314 $ 2.26
(A) Reserves include revisions to previous estimates
CHESAPEAKE ENERGY CORPORATION
ROLLFORWARD OF PROVED RESERVES
(unaudited)
Mmcfe
Beginning balance, 12/31/04 4,901,751
Extensions and discoveries 515,199
Acquisitions 583,092
Divestitures (5)
Revisions-performance 42,541
Revisions-price 25,487
Production (217,807)
Ending balance, 6/30/05 5,850,258
Reserve replacement 1,166,314
Reserve replacement rate 535%
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE
(in 000's)
(unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2005 2004 2005 2004
Oil and Gas Sales
($ in thousands):
Oil sales $96,798 $59,930 $176,742 $107,961
Oil derivatives - realized
gains (losses) (10,650) (12,878) (17,717) (21,208)
Oil derivatives - unrealized
gains (losses) 10,900 (1,470) (1,942) (7,489)
Total Oil Sales $97,048 $45,582 $157,083 $79,264
Gas sales $635,901 $415,216 $1,171,678 $775,317
Gas derivatives - realized
gains (losses) (33,702) (42,453) 13,713 (8,462)
Gas derivatives - unrealized
gains (losses) 73,154 (18,680) (31,131) (26,661)
Total Gas Sales $675,353 $354,083 $1,154,260 $740,194
Total Oil and Gas
Sales $772,401 $399,665 $1,311,343 $819,458
Average Sales Price
(excluding gains (losses)
on derivatives):
Oil ($ per bbl) $48.11 $35.82 $47.03 $34.40
Gas ($ per mcf) $6.29 $5.43 $6.00 $5.29
Gas equivalent ($ per mcfe) $6.47 $5.49 $6.19 $5.34
Average Sales Price (excluding
unrealized gains (losses)
on derivatives):
Oil ($ per bbl) $42.82 $28.12 $42.32 $27.65
Gas ($ per mcf) $5.95 $4.87 $6.07 $5.23
Gas equivalent ($ per mcfe) $6.08 $4.85 $6.17 $5.16
Interest Expense ($ in thousands):
Interest $54,710 $37,513 $102,003 $76,077
Derivatives - realized
(gains) losses (675) 353 (1,796) (405)
Derivatives - unrealized
(gains) losses (133) (9,060) (3,177) (321)
Total Interest Expense $53,902 $28,806 $97,030 $75,351
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
(in 000's)
(unaudited)
THREE MONTHS ENDED: June 30, June 30,
2005 2004
Cash provided by operating activities $566,781 $328,787
Cash (used in) investing activities (1,365,941) (864,016)
Cash provided by financing activities 799,160 422,041
SIX MONTHS ENDED: June 30, June 30,
2005 2004
Cash provided by operating activities $1,080,307 $670,557
Cash (used in) investing activities (2,539,878) (1,599,450)
Cash provided by financing activities 1,452,675 964,549
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CERTAIN FINANCIAL MEASURES
(in 000's)
(unaudited)
THREE MONTHS ENDED: June 30, June 30,
2005 2004
CASH PROVIDED BY OPERATING ACTIVITIES $ 566,781 $ 328,787
Adjustments:
Changes in assets and liabilities (53,498) (20,614)
OPERATING CASH FLOW* $ 513,283 $ 308,173
* 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 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
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, June 30,
2005 2004
Net income $ 193,779 $ 97,155
Income tax expense 111,387 54,654
Interest expense 53,902 28,806
Depreciation and amortization
of other assets 11,807 6,716
Oil and gas depreciation, depletion
and amortization 209,371 136,743
EBITDA** $ 580,246 $ 324,074
** Ebitda represents net income (loss) before cumulative effect of
accounting change, income tax expense (benefit), 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, June 30,
2005 2004
CASH PROVIDED BY OPERATING ACTIVITIES $ 566,781 $ 328,787
Changes in assets and liabilities (53,498) (20,614)
Interest expense 53,902 28,806
Unrealized gains (losses) on oil
and gas derivatives 84,054 (20,150)
Other non-cash items (70,993) 7,245
EBITDA $ 580,246 $ 324,074
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CERTAIN FINANCIAL MEASURES
(in 000's)
(unaudited)
SIX MONTHS ENDED: June 30, June 30,
2005 2004
CASH PROVIDED BY OPERATING ACTIVITIES $1,080,307 $670,557
Adjustments:
Changes in assets and liabilities (61,561) (28,830)
OPERATING CASH FLOW* $1,018,746 $641,727
* 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 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
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,
2005 2004
Net income $318,789 $209,745
Income tax expense 183,243 117,981
Interest expense 97,030 75,351
Depreciation and amortization of other assets 21,889 12,455
Oil and gas depreciation, depletion and
amortization 390,339 256,651
EBITDA** $1,011,290 $672,183
** Ebitda represents net income (loss) before cumulative effect of
accounting change, income tax expense (benefit), 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,
2005 2004
CASH PROVIDED BY OPERATING ACTIVITIES $1,080,307 $670,557
Changes in assets and liabilities (61,561) (28,830)
Interest expense 97,030 75,351
Unrealized gains (losses) on oil and
gas derivatives (33,073) (34,150)
Other non-cash items (71,413) (10,745)
EBITDA $1,011,290 $672,183
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON & ADJUSTED EBITDA
($ in 000's, except per share amounts)
(unaudited)
Three Months Six Months
Ended Ended
June 30, 2005 June 30, 2005
Net income available to
common shareholders $ 179,177 $ 298,724
Adjustments:
Loss on conversion/exchange
of preferred stock 4,743 4,743
Net Income $ 183,920 $ 303,467
Adjustments, net of tax:
Unrealized (gains) losses
on derivatives (53,458) 18,985
Loss on repurchases or
exchanges of debt 43,434 44,006
Adjusted net income available to common* $ 173,896 $ 366,458
Adjusted earnings per share
assuming dilution** $ 0.50 $ 1.06
EBITDA $ 580,246 $1,011,290
Adjustments, before tax:
Unrealized (gains) losses
on oil and gas derivatives (84,054) 33,073
Loss on repurchases or
exchanges of debt 68,400 69,300
Adjusted EBITDA* $ 564,592 $1,113,663
* Adjusted net income available to common and adjusted earnings per
share assuming dilution and adjusted EBITDA 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 and EBITDA because:
a. Management uses adjusted net income available to common and adjusted
EBITDA to evaluate the company's operational trends and performance
relative to other oil and gas producing companies.
b. Adjusted net income available to common and adjusted EBITDA are more
comparable to earnings and EBITDA 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.
** For purposes of calculating fully diluted shares and earnings per
share assuming dilution for the three and six months ended June 30,
2005, accounting rules prohibit the company from assuming the
conversion of the 4.125% preferred stock for common shares prior to
conversion or exchange for either period since the effect would have
been anti-dilutive. In determining adjusted earnings per share, we
have reflected the converted shares as though they were converted at
the beginning of the period (fully diluted share count of 366.7
million and 359.1 million for the three and six months ended June 30,
2005, respectively).
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF AUGUST 4, 2005
Quarter Ending September 30, 2005; Year Ending December 31, 2005; Year Ending
December 31, 2006.
We have adopted a policy of periodically providing investors with guidance
on certain factors that affect our future financial performance. As of
August 4, 2005, we are using the following key assumptions in our projections
for the second quarter of 2005, the full-year 2005 and the full-year 2006.
The primary changes from our May 2, 2005 Outlook are in italicized bold in
the table and are explained as follows:
1) We have updated the projected effects from changes in our hedging
positions since our May 2, 2005 Outlook.
2) We have updated certain of our cost and oil and natural gas price
differentials to reflect changing market conditions.
3) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only.
4) We have increased our capital expenditure projections to reflect
anticipated higher levels of drilling activity and continuing service
cost inflation.
Quarter Ending Year Ending Year Ending
September 30, December 31, December 31,
2005 2005 2006
Estimated Production:
Oil - Mbo 1,950 7,650 7,700
Gas - Bcf 107-109 411-417 465-475
Gas Equivalent - Bcfe 118.5-120.5 457-463 511-521
Daily gas equivalent
midpoint - in Mmcfe 1,300 1,260 1,414
NYMEX Prices (for calculation
of realized hedging effects only):
Oil - $/Bo $53.01 $51.51 $45.00
Gas - $/Mcf $7.04 $6.64 $6.50
Estimated Differentials to
NYMEX Prices:
Oil - $/Bo -$4.50 -$4.46 -$4.50
Gas - $/Mcf -$0.80 -$0.75 -$0.80
Estimated Realized Hedging Effects
(based on expected NYMEX
prices above):
Oil - $/Bo -$0.33 -$2.07 $4.34
Gas - $/Mcf -$0.20 $0.19 $0.33
Operating Costs per Mcfe of
Projected Production:
Production expense $0.68-0.72 $0.68-0.72 $0.72-0.77
Production taxes (generally 7%
of O&G revenues)(A) $0.43-0.48 $0.40-0.45 $0.40-0.45
General and administrative $0.10-0.12 $0.10-0.12 $0.11-0.13
Stock-based compensation
(non-cash) $0.03-0.05 $0.03-0.05 $0.04-0.06
DD&A - oil and gas $1.85-1.95 $1.80-1.90 $2.00-2.10
Depreciation of other assets $0.09-0.11 $0.09-0.11 $0.10-0.12
Interest expense(B) $0.45-0.49 $0.45-0.49 $0.48-0.52
Other Income and Expense per Mcfe:
Marketing and other income $0.02-0.04 $0.02-0.04 $0.02-0.04
Book Tax Rate (approximately
equal to 95% deferred) 36.5% 36.5% 36.5%
Equivalent Shares Outstanding:
Basic 318 mm 315 mm 320 mm
Diluted 372 mm 366 mm 375 mm
Capital Expenditures:
Drilling, leasehold and
seismic $485-$535mm $1,900-$2,100mm $2,100-$2,300mm
(A) Severance tax per mcfe is based on NYMEX prices of $50.00 per bo and
natural gas prices ranging from $5.75 to $8.00 per mcf during Q3
2005, $45.00 per bo and natural gas prices ranging from $6.00 to
$8.50 per mcf during calendar 2005 and $45.00 per bo and $6.35 to
$7.25 per mcf during calendar 2006.
(B) 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 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 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 gas sales.
All realized gains and losses from oil and natural gas derivatives are
included in oil and 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 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.
The company currently has in place the following natural gas swaps:
% Hedged
Avg.
Avg. NYMEX Open Swap
NYMEX Gain Price Assuming Positions
Strike (Loss) Including Gas as a %
Open Price from Open Production of Estimated
Swaps Of Open Locked & Locked in Bcf's Total Gas
in Bcf's Swaps Swaps Positions of: Production
2005:
3rd Qtr 72.3 $6.61 -$0.15 $6.46 108.0 67%
4th Qtr 57.4 $7.08 -$0.19 $6.89 110.8 52%
Remaining
2005 (A) 129.7 $6.82 -$0.17 $6.65 218.8 59%
Total
2006 (A) 128.6 $7.42 -$0.19 $7.23 470.0 27%
Total 2007 9.9 $8.24 -$1.18 $7.06 505.0 2%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 42.6 bcf in 2005 and $3.75
to $5.50 covering 35.7 bcf in 2006.
Note: Not shown above are collars covering 3.0 bcf of production in 2005
at a weighted average floor and ceiling of $3.59 and $5.37 and 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 2005 at a
weighted average price of $6.00.
The company has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Production
Volume in in Bcf's
Bcf's NYMEX less*: of: % Hedged
Remaining 2005 96.3 $ 0.27 218.8 44%
2006 130.1 0.32 470.0 28%
2007 126.5 0.28 505.0 25%
2008 118.6 0.27 530.0 22%
2009 86.6 0.29 555.0 16%
Totals 558.1 $ 0.29 2,278.8 24%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Open Swap
Positions as %
Assuming Oil of Total
Open Swaps Avg. NYMEX Production Estimated
in mbo's Strike Price in mbo's of: Production
Q3 - 2005 888.5 $51.41 1,950 46%
Q4 - 2005 935.5 $52.99 1,942 48%
Remaining
2005(A) 1,824.0 $52.22 3,892 47%
Total 2006(A) 2,842.5 $56.75 7,700 37%
Total 2007 590.0 $53.33 7,750 8%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $26.00 to $42.00 covering 552 mbo in 2005 and $40.00 to
$42.00 covering 501.5 mbo in 2006.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF MAY 2, 2005
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF AUGUST 4, 2005
Quarter Ending June 30, 2005; Year Ending December 31, 2005; Year Ending
December 31, 2006.
We have adopted a policy of periodically providing investors with guidance
on certain factors that affect our future financial performance. As of May 2,
2005, we are using the following key assumptions in our projections for the
second quarter of 2005, the full-year 2005 and the full-year 2006.
The primary changes from our April 12, 2005 Outlook are in italicized bold
in the table and are explained as follows:
1) We have updated the projected effects from changes in our hedging
positions since our April 12, 2005 Outlook.
2) We have updated certain of our cost and oil and natural gas price
differentials to reflect changing market conditions.
3) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only.
4) We have increased our capital expenditure projections to reflect
anticipated higher levels of drilling activity and continuing service
cost inflation.
5) We have increased our estimated diluted share count to reflect the
common shares issuable upon conversion of our recently issued
$460 million preferred stock issuance.
Quarter Ending Year Ending Year Ending
June 30, 2005 December 31, 2005 December 31, 2006
Estimated Production:
Oil - Mbo 1,770 7,000 7,300
Gas - Bcf 98-100 403-411 457-467
Gas Equivalent -
Bcfe 108.5-110.5 445-453 501-511
Daily gas equivalent
midpoint -in Mmcfe 1,203 1,230 1,386
NYMEX Prices (for
calculation of
realized hedging
effects only):
Oil - $/Bo $45.00 $46.21 $45.00
Gas - $/Mcf $6.78 $6.51 $6.50
Estimated Differentials
to NYMEX Prices:
Oil - $/Bo -$4.00 -$4.00 -$4.00
Gas - $/Mcf -$0.80 -$0.80 -$0.80
Estimated Realized
Hedging Effects
(based on expected
NYMEX prices above):
Oil - $/Bo -$0.65 -$0.65 $1.52
Gas - $/Mcf -$0.25 $0.17 $0.11
Operating Costs per Mcfe
of Projected Production:
Production expense $0.68-0.72 $0.68-0.72 $0.72-0.77
Production taxes
(generally 7% of
O&G revenues) (A) $0.40-0.45 $0.40-0.45 $0.40-0.45
General and
administrative $0.10-0.12 $0.10-0.12 $0.11-0.13
Stock-based
compensation
(non-cash) $0.03-0.05 $0.03-0.05 $0.04-0.06
DD&A - oil and gas $1.75-1.85 $1.75-1.85 $1.85-1.95
Depreciation of
other assets $0.09-0.11 $0.09-0.11 $0.10-0.12
Interest expense (B) $0.43-0.47 $0.43-0.47 $0.43-0.47
Other Income and
Expense per Mcfe:
Marketing and other
income $0.02-0.04 $0.02-0.04 $0.02-0.04
Book Tax Rate
(approximately equal
to 95% deferred) 36.5% 36.5% 36.5%
Equivalent Shares
Outstanding:
Basic 312 mm 315 mm 318 mm
Diluted 370 mm 366 mm 373 mm
Capital Expenditures:
Drilling, leasehold
and seismic $425-$475mm $1,700-$1,900mm $1,900-$2,100mm
(A) Severance tax per mcfe is based on NYMEX prices of $45.00 per barrel
of oil and natural gas prices ranging from $6.00-$7.20 during Q2
2005, $6.50-$7.50 during calendar 2005, and $6.35-$7.25 during
calendar 2006.
(B) 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 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 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 gas sales.
All realized gains and losses from oil and natural gas derivatives are
included in oil and 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 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.
The company currently has in place the following natural gas swaps:
% Hedged
Avg.
Avg. NYMEX Open Swap
NYMEX Gain Price Assuming Positions
Strike (Loss) Including Gas as a %
Open Price from Open Production of Estimated
Swaps Of Open Locked & Locked in Bcf's Total Gas
in Bcf's Swaps Swaps Positions of: Production
2005:
1st Qtr 62.2 $7.00 -$0.18 $6.82 94.1 66%
2nd Qtr 64.0 $6.30 -$0.16 $6.14 99.0 65%
3rd Qtr 59.8 $6.46 -$0.18 $6.28 105.5 57%
4th Qtr 40.9 $6.73 -$0.27 $6.46 108.4 38%
Total
2005(A) 226.9 $6.61 -$0.19 $6.42 407.0 56%
Total
2006(A) 82.1 $7.14 -$0.29 $6.85 462.0 18%
TOTALS
2005-2006 309.0 $6.75 -$0.22 $6.53 869.0 36%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 79.5 bcf in 2005 and $3.75
to $5.50 covering 35.7 bcf in 2006.
Note: Not shown above are collars covering 4.4 bcf of production in 2005
at a weighted average floor and ceiling of $3.10 and $4.44 and call
options covering 7.3 bcf of production in 2005 at a weighted average
price of $6.00.
The company has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Production
Volume in Bcf's NYMEX less*: in Bcf's of: % Hedged
2005 188.6 $ 0.26 407.0 46%
2006 130.1 0.32 462.0 28%
2007 126.5 0.28 490.0 26%
2008 118.6 0.27 515.0 23%
2009 86.6 0.29 540.0 16%
Totals 650.4 $ 0.28 2,414.0 27%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Open Swap
Positions as %
Avg. Assuming Oil of Total
Open Swaps NYMEX Production in Estimated
in mbo's Strike Price mbo's of: Production
Q1 - 2005 870.5 $41.87 1,746 50%
Q2 - 2005 1,137.0 $43.98 1,750 65%
Q3 - 2005 614.0 $48.46 1,750 35%
Q4 - 2005 521.5 $48.46 1,754 30%
Total 2005 (A) 3,143.0 $45.01 7,000 45%
Total 2006 (A) 1,200.0 $54.77 7,300 16%
Total 2007 365.0 $50.79 7,300 5%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $26.00 to $42.00 covering 2,317 mbo in 2005 and $40.00
to $42.00 covering 501.5 mbo in 2006.
SOURCE Chesapeake Energy Corporation
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Related links:
http://www.chkenergy.com
CONTACT:
investors, Jeffrey L. Mobley, CFA, Vice
President-Investor Relations and Research, +1-405-767-4763, or
jmobley@chkenergy.com , or media, Thomas S. Price, Jr., Senior
Vice President-Corporate Development, +1-405-879-9257, or
tprice@chkenergy.com , both of Chesapeake Energy Corporation
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