EXHIBIT 99.1
------------
CHESAPEAKE ENERGY CORPORATION POSTS STRONG RESULTS FOR THE
2004 SECOND QUARTER AND ANNOUNCES $590 MILLION OF
NATURAL GAS ACQUISITIONS IN THE MID-CONTINENT AND SOUTH TEXAS
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, OKLAHOMA, JULY 26, 2004 - 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 $1.52 per mcfe.
Reserve replacement through the drillbit was 143 bcfe, or 165%, and reserve
replacement through acquisitions was 286 bcfe, or 331%. At the end of the second
quarter, Chesapeake`s estimated proved reserves were 3.8 trillion cubic feet of
natural gas equivalent (tcfe) (4.1 tcfe pro forma for the acquisitions announced
today).
KEY OPERATIONAL AND FINANCIAL STATISTICS FOR THE 2004 SECOND QUARTER
The table below summarizes Chesapeake's key statistics during the 2004 second
quarter and compares them to the 2004 first quarter and the 2003 second quarter:
THREE MONTHS ENDED:
-------------------
6/30/04 03/31/04 06/30/03
------- -------- -------
Average daily production (in mmcfe) 951 867 740
Gas as % of total production 88 89 89
Natural gas production (in bcf) 76.5 70.1 60.0
Average realized gas price ($/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 ($/mcfe) 3.74 4.41 3.96
Net income to common shareholders 85.8 104.4 76.3
($ in millions)
(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.
2
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.
3
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.
4
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."
5
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 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
WWW.CHKENERGY.COM.
6
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
106,857
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
========== ===========
7
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
106,857
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
========== ============ =========== ==========
- ---------------------------------------------------------------------------------------------------------------------
8
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 $4,572,291
========== ==========
COMMON SHARES OUTSTANDING 242,790 216,784
========== ==========
9
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE
THREE MONTHS ENDED SIX MONTHS ENDED
--------------------------- --------------------------
JUNE 30, JUNE 30,
--------------------------- --------------------------
2004 2003 2004 2003
------------ ------------- ------------ -----------
OIL AND GAS SALES ($ 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): $ 35.82 $ 26.77 $ 34.40 $ 29.73
Oil ($ per bbl)
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
=====================================================================================================
10
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.
11
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
=============== ==============
12
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EARNINGS & ADJUSTED EBITDA
($ IN 000'S, EXCEPT PER SHARE AMOUNTS)
=====================================================================================================
THREE MONTHS ENDED SIX MONTHS 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 20,150 34,150
hedging
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.
13
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 in italicized bold and
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 Ending Quarter Ending Year Ending Year Ending
September 30, December 31, December 31, December 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
14
(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:
15
% Hedged
-------------------------
Avg. Avg. NYMEX Open Swap
NYMEX Price Positions as
Strike Including Assuming a % of
Open Price Gain (Loss) Open and Gas Estimated
Swaps of Open from Locked Locked Production Total Gas
in Bcf's Swaps Swaps Positions in Bcf's of: 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(1) 56.3 $5.34 -$0.09 $5.25 82.5 68%
4th Qtr(1) 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(1) 61.3 $5.24 -$0.50 $4.74 357.0 17%
===========================================================================================
===========================================================================================
Total 2006(1)(2) - - - - 375.0 -
===========================================================================================
===========================================================================================
Total 2007(2) - - - - 395.0 -
- -------------------------------------------------------------------------------------------
===========================================================================================
TOTALS
- -------------------------------------------------------------------------------------------
2004-2007 284.3 $5.43 -$0.29 $5.14 1,443.1 24%
===========================================================================================
(1) 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.
(2) 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.
(3) 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.
16
The company has also entered into the following natural gas basis protection
swaps:
Assuming Gas
Production in Bcf's
Volume in Bcf's NYMEX less: 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
---------------------------------
Assuming Open Swap
Avg. Oil Positions as
Open NYMEX Prodution % of Total
Swaps in Strike in mbo's Estimated
Mmbo's Price of: Production
-------- ------ ---------- ------------
Q1 - 2004 1,270 $28.58 1,465 87%
Q2 - 2004 1,540 $30.00 1,673 92%
Q3 - 2004(1) 1,519 $30.32 1,600 95%
Q4 - 2004(1) 1,518 $30.10 1,600 95%
--------------------------------------------------------------
Total 2004(1) 5,847 $29.80 6,338 92%
===============================================================
Total 2005(1) 548 $31.56 6,360 9%
===============================================================
(1) 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.
17
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 in italicized bold and
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 December 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).
18
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. Avg. NYMEX Open Swap
NYMEX Price Positions as
Strike Including Assuming a % of
Open Price Gain from Open and Gas Estimated
Swaps of Open Locked Locked Production Total Gas
in Bcf's Swaps Swaps Positions in Bcf's of: 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%
==============================================================================================
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The company has also entered into the following natural gas basis protection
swaps:
Assuming Gas
Annual Production in Bcf's
Volume in Bcf's NYMEX less: 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
---------------------------------
Assuming Open Swap
Avg. Oil Positions as
Open NYMEX Prodution % of Total
Swaps in Strike in Mmbo's Estimated
Mmbo's Price of: 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.
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