Company Reports 2004 Second Quarter Net Income Available to Common
Shareholders of $86 Million on Revenue of $574 Million and Production of
86.5 Bcfe; Continuing Production Gains from the Drillbit and From Acquisitions
Drive Forecasts Higher for Second Half of 2004 and for 2005
Newly Announced Acquisitions Provide 310 Bcfe of Estimated Proved Reserves,
453 Bcfe of Estimated Probable and Possible Reserves, 50,000 Net Leasehold
Acres and Production of 60 Mmcfe per Day; Assets Are 92% Natural Gas and Are
Located 56% in the Mid-Continent and 44% in South Texas
OKLAHOMA CITY, July 26 /PRNewswire-FirstCall/ -- Chesapeake Energy
Corporation (NYSE: CHK) today reported its financial and operating results for
the 2004 second quarter. For the quarter, Chesapeake generated net income
available to common shareholders of $85.8 million ($0.31 per fully diluted
common share), operating cash flow of $308.2 million (defined as cash flow
from operating activities before changes in assets and liabilities) and ebitda
of $324.1 million (defined as income before income taxes, interest expense,
and depreciation, depletion and amortization expense) on revenue of
$574.3 million.
The company's 2004 second quarter net income available to common
shareholders and ebitda include an unrealized after-tax mark-to-market loss of
$7.1 million ($0.02 per fully diluted common share) resulting from the
company's oil and natural gas and interest rate hedging programs. This is an
item typically excluded from analysts' estimates.
If such item is excluded, Chesapeake's net income to common shareholders
in the 2004 second quarter would have been $92.9 million ($0.33 per fully
diluted common share) and ebitda would have been $344.2 million. This item
does not affect the calculation of operating cash flow.
Oil and Natural Gas Production and Proved Reserves Set Records
Production for the 2004 second quarter was 86.5 billion cubic feet of
natural gas equivalent (bcfe), an increase of 19.2 bcfe, or 29%, over the
67.3 bcfe produced in the 2003 second quarter and an increase of 7.6 bcfe, or
10%, over the 78.9 bcfe produced in the 2004 first quarter. The 19.2 bcfe
increase in this year's second quarter production over 2003 second quarter
production consisted of 7.7 bcfe generated from organic drillbit growth and
11.5 bcfe generated from acquisitions. Chesapeake's organic growth rate
during the past 12 months has therefore been 11%, well above the company's
forecasted organic growth rate of 5% and among the very best organic growth
performances reported by public mid- and large-cap E&P companies in the past
several years. In addition, the balance between Chesapeake's growth through
the drillbit and growth through acquisitions reflects the successful execution
of the company's balanced growth strategy.
The 2004 second quarter's production of 86.5 bcfe was comprised of
76.5 billion cubic feet of natural gas (bcf) (88% on a natural gas equivalent
basis) and 1.67 million barrels of oil and natural gas liquids (mmbo) (12% on
a natural gas equivalent basis). Chesapeake's average daily production rate
for the quarter was 951 million cubic feet of natural gas equivalent
production (mmcfe), consisting of 841 mmcf of gas and 18,385 barrels of oil
and natural gas liquids. The 2004 second quarter was Chesapeake's 12th
consecutive quarter of sequential production growth. During these 12
quarters, Chesapeake's production has increased 121%, for an average compound
quarterly growth rate of 6.8% and an average annualized growth rate of 30%.
Average prices realized during the 2004 second quarter (including realized
gains or losses from oil and gas derivatives, but excluding unrealized gains
or losses on such derivatives) were $28.12 per barrel of oil (bo) and $4.87
per thousand cubic feet of natural gas (mcf), for a realized gas equivalent
price of $4.85 per thousand cubic feet of natural gas equivalent (mcfe).
Chesapeake's average realized pricing differentials to NYMEX during the
quarter were a negative $2.19 per bo and a negative $0.68 per mcf. Realized
gains or losses from hedging activities generated a $7.70 loss per bo and a
$0.56 loss per mcf, for a 2004 second quarter realized hedging loss of
$55.3 million, or $0.64 per mcfe. This contrasts with $25.7 million, or
$0.33 per mcfe, of realized hedging gains in the 2004 first quarter.
During the 2004 second quarter, the company replaced its 86.5 bcfe of
production with an internally estimated 429 bcfe of new proved reserves, for a
reserve replacement rate of 496% at a drilling and acquisition cost of $1.52
per mcfe. Reserve replacement through the drillbit was 143 bcfe, or 165%, and
reserve replacement through acquisitions was 286 bcfe, or 331%. At the end of
the second quarter, Chesapeake's estimated proved reserves were 3.8 trillion
cubic feet of natural gas equivalent (tcfe) (4.1 tcfe pro forma for the
acquisitions announced today).
Key Operational and Financial Statistics for the 2004 Second Quarter
The table below summarizes Chesapeake's key statistics during the 2004
second quarter and compares them to the 2004 first quarter and the 2003 second
quarter:
Three Months Ended:
6/30/04 3/31/04 6/30/03
Average daily production (in mmcfe) 951 867 740
Gas as % of total production 88 89 89
Natural gas production (in bcf) 76.5 70.1 60.0
Average realized gas price ($/mcf) (A) 4.87 5.62 4.73
Oil production (in mbbls) 1,673 1,465 1,224
Average realized oil price ($/bo) (A) 28.12 27.10 26.24
Natural gas equivalent production (in bcfe) 86.5 78.9 67.3
Gas equivalent realized price ($/mcfe) (A) 4.85 5.50 4.70
General and administrative costs ($/mcfe) (E) .09 .10 .08
Production taxes ($/mcfe) .26 .19 (D) .25
Lease operating expenses ($/mcfe) .57 .57 .51
Interest expense ($/mcfe) (A) .44 .48 .56
DD&A of oil and gas properties ($/mcfe) 1.58 1.52 1.36
Operating cash flow ($ in millions) (B) 308.2 333.6 226.1
Operating cash flow ($/mcfe) 3.56 4.23 3.36
Ebitda ($ in millions) (C) 324.1 348.1 266.4
Ebitda ($/mcfe) 3.74 4.41 3.96
Net income to common shareholders
($ in millions) 85.8 104.4 76.3
(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) defined as cash flow provided by operating activities before changes
in assets and liabilities
(C) defined as income before income taxes, interest expense, and
depreciation, depletion and amortization expense
(D) includes pre-tax benefit of $6.8 million, or $0.09 per mcfe, from
prior period severance tax credits
(E) excludes expenses associated with non-cash stock based compensation
Chesapeake Announces $590 Million of Completed or Pending Acquisitions,
Acquiring 310 Bcfe of Estimated Proved Reserves, 453 Bcfe of Estimated
Probable and Possible Reserves, 50,000 Net Leasehold
Acres and 60 Mmcfe of Daily Production
Chesapeake announced that it has entered into agreements to acquire
natural gas assets in the Mid-Continent and South Texas regions through
transactions with three private companies. The transactions involve the
acquisition of Tulsa-based Bravo Natural Resources, Inc., the acquisition of
substantially all the assets of Houston-based Legend Natural Gas, LP and the
acquisition of substantially all the assets of Oklahoma City-based Tilford
Pinson Exploration, LLC.
Bravo's assets consist of 20,000 acres located in the Granite Wash-
producing Stiles Ranch and Allison Britt fields of the Anadarko Basin in
Wheeler and Hemphill Counties, Texas and Roger Mills County, Oklahoma. The
Granite Wash is a Pennsylvanian-aged formation located at depths of 12-13,000'
on Bravo's 20,000 net acres of leasehold. The Granite Wash, and the deeper
Cherokee/Atoka Washes, to date have produced more than 1.2 tcfe from 10 major
fields in the Anadarko Basin and are currently the subject of intense industry
drilling programs in western Oklahoma and in the Texas Panhandle. Chesapeake
now has more than 200,000 net acres of potentially prospective leasehold in
areas where well costs currently average $1.2-1.5 million, estimated per well
reserve recoveries average 1.5-2.0 bcfe and drainage areas average
approximately 40 acres. Bravo was formed in early 2003 by Charles R.
Stephenson, John H. Hale and Irving, Texas-based Natural Gas Partners VI, L.P.
The transaction is expected to close on August 2, subject to satisfaction of
customary closing conditions. Bravo was advised in its sale to Chesapeake by
Petrie Parkman & Co.
Legend's producing assets and 18,000 net acres of leasehold are located in
the Roleta, Haynes, Comitas and En Seguido fields in the Zapata County portion
of South Texas. The primary zones of production in these fields are various
sands of the Middle and Lower Wilcox formations at depths ranging from 7,000-
13,000'. The majority of Legend's assets are located approximately 3-7 miles
south and east of the Zapata County assets Chesapeake acquired in October 2003
from Laredo Energy LP. At the time of acquisition by Chesapeake, the Laredo
assets were producing 30 mmcfe per day net to Chesapeake's interest. After
better than expected drilling results, the Laredo assets are currently
producing 50 mmcfe per day, a 67% increase in just nine months. Zapata County
is Texas' most prolific natural gas producing county. Upon closing the Legend
transaction, Chesapeake will be the fourth largest gas producer in Zapata
County. Legend was formed in 2001 by James A. Winne, III, Michael Becci and
New York-based Riverstone Holdings LLC. The transaction is expected to close
on August 31, subject to satisfaction of customary closing conditions. Legend
was advised in its sale to Chesapeake by Goldman, Sachs & Co.
Tilford Pinson's producing assets and 12,000 net acres of leasehold are
located primarily in the Arkoma Basin fields of Northwest Scipio, Northwest
Reams and South Pine Hollow in Pittsburg County, Oklahoma. Major zones of
production in these fields range from 2,500 foot Hartshorne sands to 6,000 -
8,000' Cromwell and Caney Shale plays. The Cromwell and Caney Shale
formations are particularly active and the Caney Shale is considered by some
industry observers to have similar characteristics to the Barnett Shale. By
virtue of its drilling activities in the past six years and the completion of
the Oxley acquisition in May 2003, Chesapeake has become the largest gas
producer in Pittsburg County, Oklahoma's eighth largest gas producing county.
Tilford Pinson was formed in 1995 by Max Tilford and Dave Pinson. The
transaction closed earlier this month.
Through these three transactions, Chesapeake anticipates acquiring an
internally estimated 310 bcfe of proved reserves, an internally estimated
453 bcfe of probable and possible reserves and current production of 60 mmcfe
per day. Pro forma for these acquisitions, the company's estimated proved oil
and natural gas reserves as of June 30, 2004 would have been approximately
4.1 tcfe. Chesapeake believes it can increase the newly acquired properties'
production from the current rate of 60 mmcfe per day to at least 90 mmcfe per
day by year-end 2005 and at least 120 mmcfe per day by year-end 2006. The
company has identified approximately 210 proved undeveloped and 410 probable
and possible locations on the 50,000 net leasehold acres being acquired in the
transactions announced today.
After allocating approximately $190 million of the combined $590 million
purchase price to unevaluated leasehold and mid-stream gas assets,
Chesapeake's acquisition cost per mcfe of proved reserves will be $1.29.
Including the $190 million of unevaluated leasehold and mid-stream gas assets
value and the $690 million of anticipated future drilling costs necessary to
fully develop the proved, probable and possible reserves, the company
estimates that its all-in cost to develop the 763 bcfe of reserves acquired in
the three transactions will be $1.68 per mcfe. Chesapeake believes this is a
very attractive all-in acquisition price, especially given the industry's
present finding costs, which the company believes are currently over $2.00 per
mcfe and are likely to rise in the foreseeable future.
The acquired proved reserves have a reserves-to-production index of
14.2 years, are 92% gas, 97% company-operated, 35% proved developed and have
current lease operating expenses of only $0.29 per mcfe. These very low lease
operating expenses (approximately 60% per mcfe below the industry average)
create unusually high economic values per mcfe of proved reserves and add to
the attractiveness of Chesapeake's all-in acquisition cost of $1.68 per mcfe.
The company intends to finance the $590 million of new acquisitions using
an approximate 50/50 combination of senior notes and common stock issuance.
Operational Results Continue to Exceed Expectations, Strong Drilling Results
and Significant Leasehold Additions Lead to Increased Estimates of 5,000
Undrilled Locations and Three Tcfe of Undeveloped Reserves
Chesapeake's exploratory and development drilling programs and its
production enhancement operations on its base and recently acquired properties
continue to produce operational results that exceed the company's forecasts.
During the 2004 second quarter, Chesapeake drilled 134 gross (96.6 net)
operated wells and participated in another 187 gross wells (24.5 net) operated
by other companies. The company's drilling success rate was 98% for company-
operated wells and 99% for non-operated wells. Chesapeake invested
$149 million in operated wells and $52 million in non-operated wells.
During the quarter, the company invested $101 million in acquiring new
leasehold and 3-D seismic data as it continued to make significant investments
in the building blocks of future organic growth. In addition to adding
significant leasehold to its existing dominant positions in Bray, Mayfield,
Sahara and other ongoing Anadarko and Arkoma Basin projects, Chesapeake also
has been aggressively building industry-leading leasehold positions in the
Granite Wash and Cherokee/Atoka Wash gas resource plays in the Anadarko Basin
(approximately 200,000 prospective acres), in the Hartshorne Coal and Caney
Shale gas resource plays of the Arkoma Basin (approximately 75,000 prospective
acres) and in the Barnett Shale gas resource play in North Texas
(approximately 30,000 prospective acres in Johnson County). The company
believes it has built the largest onshore U.S. inventories of leasehold and
3-D seismic in the industry (more than three million and eight million acres,
respectively) and believes it has identified more than 5,000 undrilled
locations which could contain up to approximately four tcfe of probable and
possible undeveloped reserves.
Strong Operational Results Lead to Another Increase in 2004 Production
Forecasts and to a Strong Initial 2005 Production Forecast
Chesapeake is today increasing its 2004 mid-point production forecast by
10.0 bcfe (2.9%) to a range of 353-355 bcfe (967 mmcfe per day at the mid-
point) from a range of 341-347 (940 mmcfe per day at the mid-point).
Approximately 8.8 bcfe of this 10.0 bcfe increase is attributable to
anticipated production from the three new transactions while 1.2 bcfe is
attributable to better than expected recent drilling results. This is the
third time in 2004 that Chesapeake has increased its production forecasts,
each time from a combination of acquisitions and better than expected drilling
results. The company forecasts that its organic growth rate will be at least
10% in 2004.
Chesapeake now estimates that its third quarter 2004 production will range
from 91.5 to 92.5 bcfe (1,000 mmcfe per day at the midpoint) and its fourth
quarter 2004 production will range from 96 to 97 bcfe (1,049 mmcfe per day at
the midpoint). Chesapeake's average daily production in the second half of
2004 (1,024 mmcfe per day at the midpoint) is expected to exceed production in
the second half of 2003 (784 mmcfe per day) by approximately 240 mmcfe, or
31%. Furthermore, Chesapeake believes that its production will continue
growing during 2005 and will range between 390 and 400 bcfe (1,082 mmcfe per
day at the midpoint), a 12% increase over the midpoint of forecasted 2004
production.
Chesapeake Takes Advantage of Recent Natural Gas Price Weakness
and Lifts Some of its Natural Gas Price Hedges
Chesapeake took advantage of natural gas price weakness during the second
quarter and lifted all of its hedges for 2006 and 2007 natural gas production
and decreased its hedged natural gas positions by 10% for the second half of
2004 and 39% for 2005. The following tables compare Chesapeake's projected
2004-2007 oil and natural gas production volumes that have been hedged as of
July 26, 2004 to what had been previously hedged as of May 11, 2004.
Hedged Positions as of July 26, 2004
Oil Natural Gas
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2004 1Q 87% $28.58 99% $5.97
2004 2Q 92% $30.00 81% $5.15
2004 3Q 95% $30.32 68% $5.25
2004 4Q 95% $30.10 40% $5.12
2004 Total 92% $29.80 71% $5.41
2005 9% $31.56 17% $4.74
2006 --- --- --- ---
2007 --- --- --- ---
Hedged Positions as of May 11, 2004
Oil Natural Gas
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2004 1Q 87% $28.58 99% $5.97
2004 2Q 100% $30.00 81% $5.11
2004 3Q 96% $30.32 73% $5.28
2004 4Q 95% $30.10 48% $5.27
2004 Total 95% $29.80 74% $5.44
2005 9% $31.56 28% $5.12
2006 --- --- 10% $4.88
2007 --- --- 7% $4.76
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 2004 forecasts and initial 2005 forecast are
attached to this release in an Outlook dated July 26, 2004 labeled Schedule
"A". This Outlook has been changed from the Outlook dated May 11, 2004
(attached as Schedule "B" for investors' convenience) to reflect today's
increased production forecasts and the projected effects from the hedging
position changes.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented,
"Today's announcements of very strong operational and financial results for
the 2004 second quarter and of three new value-creating acquisitions provide
ongoing confirmation that Chesapeake continues to execute with precision on
its business strategy. This strategy focuses on delivering growth through a
balance of acquisitions and organic drilling, focusing on natural gas to take
advantage of strong long-term supply/demand fundamentals and building dominant
regional scale to achieve low operating costs and high returns on capital.
This business strategy has worked very well for our shareholders, generating a
1,525% increase in our common stock price since January 1, 1999. 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 in the years ahead."
Conference Call Information
A conference call has been scheduled for Tuesday morning, July 27, 2004 at
9:00 a.m. EDT to discuss this earnings release. The telephone number to
access the conference call is 913.981.5572. For those unable to participate
in the conference call, a replay will be available from 12:00 p.m. EDT,
July 27, 2004 through midnight EDT on August 9, 2004. The number to access
the conference call replay is 719.457.0820 and the passcode is 151543. 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
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 our prospectus dated July 8,
2004 filed with the Securities and Exchange Commission on July 12, 2004. They
include the volatility of oil and gas prices; adverse effects our substantial
indebtedness and preferred stock obligations could have on our operations and
future growth; our ability to compete effectively against strong independent
oil and gas companies and majors; possible financial losses and significant
collateral requirements as a result of our commodity price and interest rate
risk management activities; uncertainties inherent in estimating quantities of
oil and gas reserves, including reserves we acquire; projecting future rates
of production and the timing of development expenditures; exposure to
potential liabilities of acquired properties and companies; our ability to
replace reserves; the availability of capital; writedowns of oil and gas
carrying values if commodity prices decline; environmental and other claims in
excess of insured amounts resulting from drilling and production operations;
and the loss of key personnel. 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. 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" and "possible" reserves or other descriptions of 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.
The announcement of proposed financings through the issuance of equity and
debt in this press release shall not constitute an offer to sell or a
solicitation of an offer to buy any securities. The debt securities will
likely not be registered under the Securities Act of 1933 or any state
securities laws, and 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 one of the five largest independent U.S.
natural gas producers. Headquartered in Oklahoma City, the company's
operations are focused on exploratory and developmental drilling and producing
property acquisitions in the Mid-Continent, Permian Basin, South Texas, Texas
Gulf Coast and Ark-La-Tex 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, 2004 June 30, 2003
$ $/mcfe $ $/mcfe
REVENUES:
Oil and gas sales 399,665 4.62 319,519 4.74
Oil and gas marketing sales 174,627 2.02 110,296 1.64
Total Revenues 574,292 6.64 429,815 6.38
OPERATING COSTS:
Production expenses 49,595 0.57 34,263 0.51
Production taxes 22,751 0.26 17,101 0.25
General and administrative
expenses:
General and administrative
(excluding stock based
compensation) 7,420 0.09 5,635 0.08
Stock based compensation 672 0.01 365 0.01
Oil and gas marketing expenses 171,115 1.98 106,857 1.59
Oil and gas depreciation,
depletion, and amortization 136,743 1.58 91,570 1.36
Depreciation and amortization
of other assets 6,716 0.08 4,122 0.06
Total Operating Costs 395,012 4.57 259,913 3.86
INCOME FROM OPERATIONS 179,280 2.07 169,902 2.52
OTHER INCOME (EXPENSE):
Interest and other income 1,335 0.01 781 0.01
Interest expense (28,806) (0.33) (38,036) (0.56)
Total Other Income (Expense) (27,471) (0.32) (37,255) (0.55)
Income Before Income Taxes 151,809 1.75 132,647 1.97
Income Tax Expense:
Current --- --- --- ---
Deferred 54,654 0.63 50,407 0.75
Total Income Tax Expense 54,654 0.63 50,407 0.75
NET INCOME 97,155 1.12 82,240 1.22
Preferred Stock Dividends (11,344) (0.13) (5,979) (0.09)
NET INCOME AVAILABLE TO
COMMON SHAREHOLDERS 85,811 0.99 76,261 1.13
EARNINGS PER COMMON SHARE:
Basic $0.36 $0.36
Assuming dilution $0.31 $0.31
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING
(in 000's)
Basic 241,147 214,341
Assuming dilution 303,483 263,919
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
SIX MONTHS ENDED: June 30, 2004 June 30, 2003
$ $/mcfe $ $/mcfe
REVENUES:
Oil and gas sales 819,458 4.95 605,538 4.88
Oil and gas marketing sales 317,963 1.92 200,604 1.62
Total Revenues 1,137,421 6.87 806,142 6.50
OPERATING COSTS:
Production expenses 94,398 0.57 65,720 0.53
Production taxes 37,687 0.23 35,698 0.29
General and administrative
expenses:
General and administrative
(excluding stock based
compensation) 15,586 0.09 11,014 0.09
Stock based compensation 2,541 0.02 365 ---
Provision for legal settlements --- --- 286 ---
Oil and gas marketing expenses 310,779 1.87 196,215 1.58
Oil and gas depreciation,
depletion, and amortization 256,651 1.55 168,184 1.36
Depreciation and amortization
of other assets 12,455 0.08 7,806 0.06
Total Operating Costs 730,097 4.41 485,288 3.91
INCOME FROM OPERATIONS 407,324 2.46 320,854 2.59
OTHER INCOME (EXPENSE):
Interest and other income 2,678 0.02 1,544 0.01
Interest expense (75,351) (0.46) (75,040) (0.60)
Loss on repurchases or exchanges
of Chesapeake debt (6,925) (0.04) --- ---
Total Other Income (Expense) (79,598) (0.48) (73,496) (0.59)
Income Before Income Taxes and
Cumulative Effect of Accounting
Change 327,726 1.98 247,358 2.00
Income Tax Expense:
Current --- --- --- ---
Deferred 117,981 0.71 93,998 0.76
Total Income Tax Expense 117,981 0.71 93,998 0.76
NET INCOME BEFORE CUMULATIVE
EFFECT OF ACCOUNTING CHANGE,
NET OF TAX 209,745 1.27 153,360 1.24
Cumulative Effect of Accounting
Change, Net of Income Tax
of $1,464,000 --- --- 2,389 0.02
NET INCOME 209,745 1.27 155,749 1.26
Preferred Stock Dividends (19,512) (0.12) (9,505) (0.08)
NET INCOME AVAILABLE TO
COMMON SHAREHOLDERS 190,233 1.15 146,244 1.18
EARNINGS PER COMMON SHARE:
Basic
Income Before Cumulative
Effect of Accounting Change $0.80 $0.70
Cumulative Effect of
Accounting Change --- 0.01
Net Income $0.80 $0.71
Assuming dilution
Income Before Cumulative Effect
of Accounting Change $0.69 $0.62
Cumulative Effect of
Accounting Change --- 0.01
Net Income $0.69 $0.63
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING
(in 000's)
Basic 239,016 205,995
Assuming dilution 301,400 247,391
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in 000's)
(unaudited)
June 30, December 31,
2004 2003
Cash $76,237 $40,581
Other current assets 461,690 301,823
TOTAL CURRENT ASSETS 537,927 342,404
Property and equipment (net) 5,706,029 4,133,117
Other assets 96,768 96,770
TOTAL ASSETS $6,340,724 $4,572,291
Current liabilities $801,102 $513,156
Long term debt 2,464,078 2,057,713
Asset retirement obligation 64,490 48,812
Long term liabilities 73,880 28,774
Deferred tax liability 497,990 191,026
TOTAL LIABILITIES 3,901,540 2,839,481
STOCKHOLDERS' EQUITY 2,439,184 1,732,810
TOTAL LIABILITIES & STOCKHOLDERS'
EQUITY $6,340,724 $4,572,291
COMMON SHARES OUTSTANDING 242,790 216,784
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE
Three Months Ended Six Months Ended
June 30, June 30,
2004 2003 2004 2003
Oil and Gas Sales
($ in thousands):
Oil sales $59,930 $32,763 $107,961 $67,903
Oil derivatives - realized
gains (losses) (12,878) (641) (21,208) (6,879)
Oil derivatives -unrealized
gains (losses) (1,470) (1,101) (7,489) (1,178)
Total oil sales 45,582 31,021 79,264 59,846
Gas sales 415,216 282,239 775,317 596,289
Gas derivatives - realized
gains (losses) (42,453) 1,811 (8,462) (84,809)
Gas derivatives -unrealized
gains (losses) (18,680) 4,448 (26,661) 34,212
Total gas sales 354,083 288,498 740,194 545,692
Total oil and
gas sales $399,665 $319,519 $819,458 $605,538
Average Sales Price
(excluding gains (losses)
on derivatives):
Oil ($ per bbl) $35.82 $26.77 $34.40 $29.73
Gas ($ per mcf) $ 5.43 $ 4.70 $ 5.29 $ 5.40
Gas equivalent ($ per mcfe) $ 5.49 $ 4.68 $ 5.34 $ 5.35
Average Sales Price (excluding
unrealized gains (losses)
on derivatives):
Oil ($ per bbl) $28.12 $26.24 $27.65 $26.72
Gas ($ per mcf) $ 4.87 $ 4.73 $ 5.23 $ 4.63
Gas equivalent ($ per mcfe) $ 4.85 $ 4.70 $ 5.16 $ 4.61
Interest Expense
($ in thousands):
Interest $(37,513) $(38,452) $(76,077) $(74,156)
Derivatives - realized
(gains) losses (353) 682 405 1,356
Derivatives - unrealized
(gains) losses 9,060 (266) 321 (2,240)
Total Interest
Expense $(28,806) $(38,036) $(75,351) $(75,040)
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
(in 000's)
(unaudited)
THREE MONTHS ENDED: June 30, June 30,
2004 2003
Cash provided by operating activities $328,787 $277,581
Cash (used in) investing activities $(864,016) $(313,485)
Cash provided by financing activities $422,041 $33,809
SIX MONTHS ENDED: June 30, June 30,
2004 2003
Cash provided by operating activities $670,557 $376,633
Cash (used in) investing activities $(1,599,450) $(1,315,774)
Cash provided by financing activities $964,549 $727,413
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CERTAIN FINANCIAL MEASURES
(in 000's)
(unaudited)
THREE MONTHS ENDED: June 30, June 30,
2004 2003
CASH PROVIDED BY OPERATING ACTIVITIES $328,787 $277,581
Adjustments:
Changes in assets and liabilities (20,614) (51,512)
OPERATING CASH FLOW* $308,173 $226,069
SIX MONTHS ENDED: June 30, June 30,
2004 2003
CASH PROVIDED BY OPERATING ACTIVITIES $670,557 $376,633
Adjustments:
Changes in assets and liabilities (28,830) 17,149
OPERATING CASH FLOW* $641,727 $393,782
* 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.
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CERTAIN FINANCIAL MEASURES
(in 000's)
(unaudited)
THREE MONTHS ENDED: June 30, June 30,
2004 2003
NET INCOME $97,155 $82,240
Deferred income tax expense 54,654 50,407
Interest expense 28,806 38,036
Depreciation and amortization
of other assets 6,716 4,122
Oil and gas depreciation, depletion
and amortization 136,743 91,570
EBITDA** $324,074 $266,375
SIX MONTHS ENDED: June 30, June 30,
2004 2003
NET INCOME BEFORE CUMULATIVE EFFECT
OF ACCOUNTING CHANGE $209,745 $153,360
Deferred income tax expense 117,981 93,998
Interest expense 75,351 75,040
Depreciation and amortization
of other assets 12,455 7,806
Oil and gas depreciation, depletion
and amortization 256,651 168,184
EBITDA** $672,183 $498,388
** 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 banks under our bank credit
facilities and is used in our financial covenants under our bank
credit facilities and our indentures governing our senior notes.
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,
2004 2003
CASH PROVIDED BY OPERATING ACTIVITIES $328,787 $277,581
Changes in assets and liabilities (20,614) (51,512)
Interest expense, realized 37,866 37,770
Unrealized gains (losses) on oil
and gas derivatives (20,150) 3,347
Other non-cash items (1,815) (811)
EBITDA $324,074 $266,375
SIX MONTHS ENDED: June 30, June 30,
2004 2003
CASH PROVIDED BY OPERATING ACTIVITIES $670,557 $376,633
Changes in assets and liabilities (28,830) 17,149
Interest expense, realized 75,672 72,800
Unrealized gains (losses) on oil and
gas derivatives (34,150) 33,034
Other non-cash items (11,066) (1,228)
EBITDA $672,183 $498,388
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EARNINGS & ADJUSTED EBITDA
($ In 000'S, except per share amounts)
Three Months Six Months
Ended Ended
June 30, 2004 June 30, 2004
Net income to common shareholders $85,811 $190,233
Adjustments, net of tax:
Unrealized (gains) losses from hedging 7,097 21,651
Loss on repurchases or exchanges of debt --- 4,432
Adjusted earnings* $92,908 $216,316
Adjusted earnings per share
assuming dilution $0.33 $0.77
EBITDA $324,074 $672,183
Adjustments, before tax:
Unrealized (gains) losses from
oil and gas hedging 20,150 34,150
Loss on repurchases or
exchanges of debt --- 6,925
Adjusted EBITDA* $344,224 $713,258
* Adjusted earnings and adjusted EBITDA, both non-GAAP financial
measures, 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 earnings and adjusted EBITDA to evaluate
the Company's operational trends and performance relative to other
oil and gas producing companies.
b. Adjusted earnings 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.
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF JULY 26, 2004
Quarter Ending September 30, 2004; Quarter Ending December 31, 2004; Year
Ending December 31, 2004; Year Ending December 31, 2005.
We have adopted a policy of periodically providing investors with guidance
on certain factors that affect our future financial performance. As of
July 26, 2004, we are using the following key assumptions in our projections
for the third and fourth quarters of 2004, the full-year 2004 and the full-
year 2005.
The primary changes from our May 11, 2004 guidance are explained as
follows:
1) We have replaced our 2004 second quarter forecast with our initial
forecasts for the 2004 third and fourth quarters, have revised our
full year 2004 forecast and have provided our initial 2005 forecast.
2) We have updated our previous production forecasts for the full year
2004 to include today's announced acquisitions and the results of
recent drilling activities. These include 30 mmcfe per day of
production beginning August 2, 2004 and an additional 30 mmcfe per
day beginning September 1, 2004 for the acquisitions and an
additional 6.5 mmcfe per day beginning July 1, 2004 for better than
expected drilling results during the second quarter.
3) We have updated the projected effects from the reductions in our
hedging positions.
4) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only. They are not a forecast of our
expectations for 2004 and 2005 oil and natural gas prices.
5) For ease of reconciliation, please note that our first quarter 2004
production was 78.9 bcfe, our second quarter 2004 production was 86.5
bcfe and our first half 2004 production was 165.4 bcfe. Our May 11,
2004 Outlook forecasted a second quarter 2004 production range of 83-
84 bcfe and a full year 2004 production range of 341-347 bcfe.
6) Solely for the purposes of this Schedule "A" we have included the
projected effects of financing the recently announced acquisitions
with the issuance of $300 million of long-term debt securities and 23
million shares of common stock (including a 3 million share over-
allotment option). There is no assurance we will make or complete
such offerings.
Quarter Quarter Year Year
Ending Ending Ending Ending
Sept. 30, Dec. 31, Dec. 31, Dec. 31,
2004 2004 2004 2005
Estimated Production:
Oil - Mbo 1,600 1,600 6,340 6,360
Gas - Bcf 82 - 83 86.5 - 87.5 315 - 317 352 - 362
Gas Equivalent
- Bcfe 91.5 - 92.5 96 - 97 353 - 355 390 - 400
Daily gas
equivalent
midpoint -
in Mmcfe 1,000 1,049 967 1,082
NYMEX Prices (for
calculation of
realized hedging
effects only):
Oil - $/Bo $34.00 $32.00 $34.87 $30.00
Gas - $/Mcf $5.71 $5.50 $5.73 $5.00
Estimated Differentials
to NYMEX Prices:
Oil - $/Bo -$2.75 -$2.75 -$2.75 -$2.75
Gas - $/Mcf -$0.75 -$0.75 -$0.75 -$0.75
Estimated Realized
Hedging Effects
(based on expected
NYMEX prices above):
Oil - $/Bo -$3.52 -$1.82 -$4.70 $0.13
Gas - $/Mcf -$0.23 $0.01 -$0.09 $0.11
Operating Costs
per Mcfe of
Projected
Production:
Production
expense $0.57 - 0.62 $0.57 - 0.62 $0.57 - 0.62 $0.60 - 0.65
Production taxes
(generally 7%
of O&G
revenues) $0.34 - 0.38 $0.34 - 0.38 $0.28 - 0.33 $0.30 - 0.35
General and
administrative $0.10 - 0.11 $0.10 - 0.11 $0.10 - 0.11 $0.10 - 0.11
Stock based
compensation
(non-cash) $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 $0.06 - 0.07
DD&A - oil
and gas $1.60 - 1.65 $1.60 - 1.65 $1.60 - 1.65 $1.65 - 1.70
Depreciation of
other assets $0.08 - 0.10 $0.08 - 0.10 $0.08 - 0.10 $0.08 - 0.10
Interest
expense (A) $0.46 - 0.50 $0.46 - 0.50 $0.45 - 0.49 $0.44 - 0.48
Other Income and
Expense per Mcfe:
Marketing and
other income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04
Book Tax Rate 36% 36% 36% 36%
Equivalent Shares
Outstanding:
Basic 256 mm 278 mm 253 mm 285 mm
Diluted (B) 319 mm 328 mm 312 mm 328 mm
Capital
Expenditures:
Drilling,
leasehold
and seismic $260 - $290 $260 - $290 $1,000 - $1,000 -
mm mm $1,100 mm $1,100 mm
(A) Does not include gains or losses on interest rate derivatives (SFAS
133).
(B) Does not include the potential conversion of the company's 4.125%
convertible preferred stock because the common stock price does not
exceed the conversion price of the preferred.
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, as a
result, 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.
NYMEX Avg. NYMEX Open Swap
Strike Gain Price Positions
Price (Loss) Including Assuming as a %
Of from Open & Gas of Estimated
Open Swaps Open Locked Locked Production Total
in Bcf's Swaps Swaps Positions in Bcf's of: Gas Production
2004:
1st Qtr 69.5 $5.94 $0.03 $5.97 70.1 99%
2nd Qtr 62.2 $5.15 $0.00 $5.15 76.5 81%
3rd Qtr (A) 56.3 $5.34 -$0.09 $5.25 82.5 68%
4th Qtr (A) 35.0 $5.39 -$0.27 $5.12 87.0 40%
Total 2004 223.0 $5.48 -$0.07 $5.41 316.1 71%
Total
2005 (A) 61.3 $5.24 -$0.50 $4.74 357.0 17%
Total
2006 (A)(B) --- --- --- --- 375.0 ---
Total
2007 (B) --- --- --- --- 395.0 ---
TOTALS
2004-2007 284.3 $5.43 -$0.29 $5.14 1,443.1 24%
(A) Certain hedging arrangements include swaps with knockout price
ranging from $3.75 to $4.75 covering 4.6 bcf in 2004, $3.75 to $4.75
covering 9.1 bcf in 2005 and $3.75 covering 7.3 bcf in 2006.
(B) Swaps covering 32.9 bcf and 25.6 bcf have been locked for 2006 and
2007. This will result in the recognition of $22.6 million and
$11.6 million of losses in 2006 and 2007, respectively, when the
hedging arrangements settle.
(C) Not shown above are collars covering 1.5 bcf and 4.4 bcf of
production in 2004 and 2005, respectively, at a weighted average
floor and ceiling of $3.10 and $4.44. In addition, call options
covering 27.4 bcf and 7.3 bcf of production in 2004 and 2005 at
weighted average price of $6.19 and $6.00 are not included in the
table above.
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
2004 157.4 0.173 316.1 50%
2005 109.5 0.156 357.0 31%
2006 47.5 0.155 375.0 13%
2007 63.9 0.166 395.0 16%
2008 64.0 0.166 415.0 15%
2009 37.0 0.160 435.0 9%
Totals 479.3 $0.164* 2,293.1 21%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Open Swap
Assuming Oil Positions
Open Swaps Avg. NYMEX Production as % of Total
in mbo's Strike Price in mbo's of: Estimated Production
Q1 - 2004 1,270 $28.58 1,465 87%
Q2 - 2004 1,540 $30.00 1,673 92%
Q3 - 2004 (A) 1,519 $30.32 1,600 95%
Q4 - 2004 (A) 1,518 $30.10 1,600 95%
Total 2004 (A) 5,847 $29.80 6,338 92%
Total 2005 (A) 548 $31.56 6,360 9%
(A) Certain hedging arrangements include swaps with a knockout price
ranging from $21.00 to $26.00 covering 2,240 mbo in 2004 and a
knockout price of $26.00 covering 548 mbo in 2005.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF MAY 11, 2004
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF JULY 26, 2004
Quarter Ending June 30, 2004; Year Ending December 31, 2004.
We have adopted a policy of periodically providing investors with guidance
on certain factors that affect our future financial performance. As of
May 11, 2004, we are using the following key assumptions in our projections
for the second quarter of 2004 and the full-year 2004.
The primary changes from our April 26, 2004 guidance are explained as
follows:
1) We have increased our production forecast for the second quarter and
full-year 2004 because of the Greystone acquisition and better than
expected recent drilling results.
2) We have included the effects of financing the Greystone transaction
with $300 million of senior notes and $125 million of bank debt.
3) We have updated the projected effects from changes in our hedging
positions.
4) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only. They are not a forecast of our
expectations for 2004 oil and natural gas prices.
Quarter Ending Year Ending
June 30, 2004 Dec. 31, 2004
Estimated Production:
Oil - Mbo 1,540 6,185
Gas - Bcf 74 - 75 304 - 310
Gas Equivalent - Bcfe 83 - 84 341 - 347
Daily gas equivalent midpoint
- in Mmcfe 918 940
NYMEX Prices (for calculation of
realized hedging effects only):
Oil - $/Bo $30.87 $30.00
Gas - $/Mcf $5.35 $5.14
Estimated Differentials to NYMEX Prices:
Oil - $/Bo -$2.75 -$2.72
Gas - $/Mcf -$0.70 -$0.71
Estimated Realized Hedging Effects
(based on expected NYMEX prices above):
Oil - $/Bo -$0.71 +$0.05
Gas - $/Mcf -$0.06 +$0.33
Operating Costs per Mcfe of
Projected Production:
Production expense $0.55 - 0.60 $0.55 - 0.60
Production taxes (generally 7% of
O&G revenues) $0.28 - 0.30 $0.28 - 0.32
General and administrative $0.10 - 0.11 $0.10 - 0.11
Stock based compensation (non-cash) $0.02 - 0.03 $0.02 - 0.03
DD&A - oil and gas $1.52 - 1.56 $1.52 - 1.60
Depreciation of other assets $0.07 - 0.09 $0.07 - 0.09
Interest expense (A) $0.49 - 0.53 $0.45 - 0.50
Other Income and Expense per Mcfe:
Marketing and other income $0.02 - 0.04 $0.02 - 0.04
Book Tax Rate 36% 36%
Equivalent Shares Outstanding:
Basic 241 mm 247 mm
Diluted 304 mm 305 mm
Capital Expenditures:
Drilling, leasehold and seismic $200 - $225 mm $875 - $925 mm
(A) Does not include gains or losses on interest rate derivatives (SFAS
133).
Commodity Hedging Activities
Periodically 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, as a
result, 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.
NYMEX Avg. NYMEX Open Swap
Strike Price Positions
Price Gain Including Assuming as a %
Of from Open & Gas of Estimated
Open Swaps Open Locked Locked Production Total
in Bcf's Swaps Swaps Positions in Bcf's of: Gas Production
2004:
1st Qtr 69.5 $5.94 $0.03 $5.97 70.1 99%
2nd Qtr 60.4 $5.11 $0.00 $5.11 74.5 81%
3rd Qtr 58.4 $5.28 $0.00 $5.28 80.0 73%
4th Qtr 39.6 $5.27 $0.00 $5.27 82.4 48%
Total
2004 227.9 $5.43 $0.01 $5.44 307.0 74%
Total
2005 88.4 $5.12 $0.00 $5.12 320.0 28%
Total
2006 32.9 $4.88 $0.00 $4.88 330.0 10%
Total
2007 25.6 $4.76 $0.00 $4.76 340.0 7%
TOTALS
2004-
2007 374.8 $5.26 $0.01 $5.27 1,297.0 29%
The company has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Annual Production
Volume in Bcf's NYMEX less: in Bcf's of: % Hedged
2004 157.4 0.173 307.0 52%
2005 109.5 0.156 320.0 34%
2006 47.5 0.155 330.0 14%
2007 63.9 0.166 340.0 19%
2008 64.0 0.166 350.0 18%
2009 37.0 0.160 360.0 10%
Totals 479.3 $0.164* 2,007.0 24%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Open Swap
Assuming Oil Positions
Open Swaps Avg. NYMEX Production as % of Total
in Mmbo's Strike Price in Mmbo's of: Estimated Production
Q1 - 2004* 1,270 $28.58 1,465 87%
Q2 - 2004* 1,540 $30.00 1,540 100%
Q3 - 2004* 1,519 $30.32 1,590 96%
Q4 - 2004* 1,518 $30.10 1,590 95%
Total 2004* 5,847 $29.80 6,185 95%
Total 2005* 548 $31.56 6,360 9%
* Swaps with a knockout price of $21.00, with the exception of 2,000
bopd in 2004 with a knockout price of $24.00, with an additional 1,000
bopd in Q2 2004 at $24.00, 1,000 bopd in Q3 and Q4 2004 with a
knockout price of $23.00, 2,000 bopd for 1/04 and 3-8/04 at a knockout
price of $22.00, 3,000 bopd in 2/04 at a knockout price of $22.00 and
1,500 bopd from 4/04 through 12/05 at a knockout price of $26.00.
SOURCE Chesapeake Energy Corporation
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Related links:
http://www.chkenergy.com
Company News On-Call:
http://www.prnewswire.com/comp/138877.html
CONTACT:
Marc Rowland, Executive Vice President and
Chief Financial Officer, +1-405-879-9232, or Tom Price, Jr.,
Senior Vice President-Investor Relations, +1-405-879-9257, both
of Chesapeake Energy Corporation
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