EXHIBIT 99.1
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CHESAPEAKE ENERGY CORPORATION REPORTS RECORD RESULTS
FOR THE FOURTH QUARTER AND FULL-YEAR 2004
COMPANY REPORTS 2004 FOURTH QUARTER NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
OF $163 MILLION ON REVENUE OF $942 MILLION AND PRODUCTION OF 103 BCFE
COMPANY REPORTS FULL-YEAR 2004 NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
OF $439 MILLION ON REVENUE OF $2,709 MILLION AND PRODUCTION OF 363 BCFE
PROVED RESERVES REACH 4.9 TCFE FROM PROVED RESERVE ADDS OF 1.7 TCFE;
RESERVE REPLACEMENT EQUALS 578% AT THE ATTRACTIVE DRILLING AND ACQUISITION
COST OF $1.21 PER MCFE; PROVED RESERVES NOW EXPECTED TO EXCEED 5.4 TCFE
BY YEAR-END 2005 AND 5.8 TCFE BY YEAR-END 2006
OIL AND NATURAL GAS PRODUCTION INCREASES 40% QUARTER-OVER-QUARTER,
35% YEAR-OVER-YEAR, AND 9% SEQUENTIAL QUARTER-OVER-QUARTER;
ORGANIC GROWTH IN 2004 REACHES 20%,
EXCEEDS 2003'S EXCELLENT ORGANIC GROWTH RATE OF 18%;
CHESAPEAKE NOW 4TH LARGEST INDEPENDENT PRODUCER OF U.S. NATURAL GAS
OKLAHOMA CITY, OKLAHOMA, FEBRUARY 22, 2005 - Chesapeake Energy Corporation
(NYSE: CHK) today reported financial and operating results for the fourth
quarter of 2004 and for the full-year 2004. For the quarter, Chesapeake
generated net income available to common shareholders of $163.2 million ($0.52
per fully diluted common share), operating cash flow of $423.7 million (defined
as cash flow from operating activities before changes in assets and liabilities)
and ebitda of $550.1 million (defined as income before income taxes, interest
expense, and depreciation, depletion and amortization expense) on revenue of
$942.1 million and production of 102.9 billion cubic feet of natural gas
equivalent (bcfe).
For the full-year 2004, Chesapeake generated net income available to common
shareholders of $439.0 million ($1.53 per fully diluted common share), operating
cash flow of $1,418.8 million and ebitda of $1,583.6 million on revenue of
$2,709.3 million and production of 362.6 bcfe.
The company's fourth quarter and full-year 2004 net income available to common
shareholders and ebitda include various items that are typically not included in
published estimates of the company's financial results by certain securities
analysts. Such items and their after-tax effects on fourth quarter and full-year
reported results are described as follows:
o an unrealized mark-to-market gain of $69.2 million for the fourth
quarter and a $22.8 million gain for the full year resulting from the
company's oil and natural gas and interest rate hedging programs;
o an $11.3 million loss for the fourth quarter and a $15.7 million loss
for the full year resulting from the early extinguishment of certain
Chesapeake debt securities;
o a $2.9 million loss for the fourth quarter and for the full year
related to the settlement of certain litigation; and
o an adjustment to net income available to common shareholders of $36.7
million representing a loss on the retirement of preferred stock
related to the exchange of substantially all of our 6.0% convertible
preferred stock for common stock in the fourth quarter.
Adjusted for the above-mentioned gains and losses and giving effect to the
issuance of common shares for preferred shares, Chesapeake's net income to
common shareholders in the fourth quarter of 2004 would have been $153.5 million
($0.44 per fully diluted common share) and ebitda would have been $464.7
million. Similarly adjusted, Chesapeake's net income to common shareholders for
the full year 2004 would have been $511.0 million ($1.56 per fully diluted
common share) and ebitda would have been $1,571.7 million. The foregoing items
do not affect the calculation of operating cash flow. A reconciliation of
operating cash flow, ebitda and adjusted net income to comparable financial
measures calculated in accordance with generally accepted accounting principles
is presented on pages 15-17 of this release.
OIL AND NATURAL GAS PRODUCTION AGAIN SETS RECORD; FOURTH QUARTER 2004
PRODUCTION UP 40% OVER FOURTH QUARTER 2003; FULL-YEAR 2004 PRODUCTION
35% HIGHER THAN FULL-YEAR 2003 PRODUCTION; SEQUENTIAL ORGANIC
GROWTH RATE 8% IN FOURTH QUARTER 2004 AND 20% IN FULL-YEAR 2004
Production for the 2004 fourth quarter was 102.9 bcfe, an increase of 29.6 bcfe,
or 40%, over the 73.3 bcfe produced in the 2003 fourth quarter and an increase
of 8.7 bcfe, or 9%, over the 94.2 bcfe produced in the 2004 third quarter. The
29.6 bcfe increase in 2004's fourth quarter production over 2003's fourth
quarter production consisted of 14.4 bcfe (49%) generated from organic drillbit
growth and 15.2 bcfe (51%) generated from acquisitions. The 8.7 bcfe increase in
sequential quarterly production consisted of 6.7 bcfe (77%) generated from
organic drillbit growth and 2.0 bcfe (23%) generated from acquisitions. The
company's 2004 fourth quarter production exceeded its December 27, 2004
forecasted 2004 fourth quarter mid-point production by 4.4 bcfe, or 4.5%,
because of stronger than expected drilling and operational results.
Production for the full-year 2004 was 362.6 bcfe, an increase of 94.2 bcfe, or
35%, over the 268.4 bcfe produced in 2003 and an increase of 181.1 bcfe, or
100%, over the 181.5 bcfe produced in 2002. The 94.2 bcfe increase in 2004's
production over 2003's production consisted of 52.2 bcfe (55%) generated from
organic drillbit growth and 42.0 bcfe (45%) generated from acquisitions.
Chesapeake's 2004 organic growth rate of 20% follows organic growth of 18% in
2003, 6% in 2002 and 9% in 2001. During these four years, Chesapeake's total
organic growth rate has been 69% and its average annual organic growth rate has
been 14%. Total company production growth was 35% in 2004, 48% in 2003, 19% in
2002 and 25% in 2001 (U.S. only). Chesapeake is projecting total company
production growth rates of 20% in 2005 and 11% in 2006 and organic growth rates
of 10% in 2005 and 10% in 2006.
Chesapeake's 2004 fourth quarter production of 102.9 bcfe was comprised of 92.2
billion cubic feet of natural gas (bcf) (90% on a natural gas equivalent basis)
and 1.79 million barrels of oil and natural gas liquids (mmbo) (10% on a natural
gas equivalent basis). Chesapeake's average daily production rate for the
quarter was 1,119 million cubic feet of natural gas equivalent production
(mmcfe), consisting of 1,002 mmcf of gas and 19,478 barrels of oil and natural
gas liquids. The 2004 fourth quarter was Chesapeake's 14th consecutive quarter
of sequential production growth. During these 14 quarters, Chesapeake's U.S.
production has increased 186%, for an average compound quarterly growth rate of
7.8% and an average compound annual growth rate of 34.6%.
Production for the full-year 2004 of 362.6 bcfe was comprised of 322.0 bcf (89%
on a natural gas equivalent basis) and 6.76 mmbo (11% on a natural gas
equivalent basis). Chesapeake's average daily production rate for the year was
991 mmcfe, consisting of 880 mmcf of gas and 18,481 barrels of oil and natural
gas liquids. The full-year 2004 was Chesapeake's 15th consecutive year of
sequential production growth. During these 15 years, Chesapeake's production has
increased at an average compound annual growth rate of 74%.
2
OIL AND NATURAL GAS PROVED RESERVES REACH RECORD LEVEL OF 4.9 TCFE;
DRILLING AND ACQUISITION COSTS ARE $1.21 PER MCFE AS COMPANY
ADDS 2.1 TCFE; RESERVE REPLACEMENT REACHES 578%
Chesapeake began 2004 with estimated proved reserves of 3,169 bcfe and ended the
year with 4,902 bcfe, an increase of 1,733 bcfe, or 55%. During 2004, the
company replaced its 363 bcfe of production with an estimated 2,096 bcfe of new
proved reserves, for a reserve replacement rate of 578% at a drilling and
acquisition cost of $1.21 per thousand cubic feet of natural gas equivalent
(mcfe). Reserve replacement through the drillbit was 962 bcfe, or 265% of
production (including 141 bcfe from performance revisions and 5 bcfe from oil
and natural gas price increases), or 46% of the total increase, at a cost of
$1.03 per mcfe. Reserve replacement through acquisitions (reduced for 4 bcfe
sold during the year) was 1,134 bcfe, or 313% of production, 54% of the total
increase, at a cost of $1.36 per mcfe.
Total costs incurred, including drilling, completion, acquisition, seismic,
leasehold, capitalized internal costs, non-cash tax basis step-up from corporate
acquisitions ($464 million in 2004, or $0.22 per mcfe, frequently booked as
goodwill in the industry), asset retirement obligations and all other
miscellaneous costs capitalized to our oil and natural gas properties were $1.80
per mcfe. These costs exclude future development costs of proved undeveloped
reserves. A complete reconciliation of finding and acquisition cost information
and a roll forward of proved reserves is presented on page 13 of this release.
Of the company's estimated proved reserves at year-end 2004, 66% were proved
developed compared to 74% in 2003, 74% in 2002 and 71% in 2001. Seventy-five
percent of this year's estimated proved reserves are covered by reports prepared
by independent third-party reservoir engineers (as opposed to reviews or audits
of internally prepared estimates), compared to 74% in 2003, 73% in 2002 and 71%
in 2001.
As of December 31, 2004, the company's estimated future net cash flows
discounted at 10% before taxes (PV-10) from its proved reserves were $10.5
billion using field differential adjusted prices of $39.91 per bo (based on a
NYMEX year-end price of $43.39 per bo) and $5.65 per mcf (based on a NYMEX
year-end price of $6.18 per mcf). In addition to the PV-10 value of proved
reserves, the Company believes that its drilling rig investments are worth $175
million, its midstream gas gathering and compression assets are worth $100
million, and its 4,000 bcfe of non-proved reserves are worth $1.0-2.0 billion.
Last year's PV-10 of its proved reserves was $7.3 billion using field
differential adjusted prices of $30.22 per bo (based on a NYMEX year-end price
of $32.47 per bo) and $5.68 per mcf (based on a NYMEX year-end price of $5.97
per mcf). Chesapeake's PV-10 changes by approximately $215 million for every
$0.10 per mcf change in gas prices and approximately $40 million for every $1.00
per bo change in oil prices. The Company's proved developed producing reserves
decline rate is projected to be 26% in the first year (2005), 18% in year two,
14% in year three, 12% in year four and 11% in year five.
AVERAGE PRICES REALIZED AND HEDGING RESULTS AND HEDGING POSITIONS DETAILED
Average prices realized during the 2004 fourth quarter (including realized gains
or losses from oil and gas derivatives, but excluding unrealized gains or losses
on such derivatives) were $28.70 per bo and $5.50 per mcf, for a realized gas
equivalent price of $5.42 per mcfe. Chesapeake's average realized pricing
differentials to NYMEX during the fourth quarter were a negative $3.20 per bo
and a negative $1.19 per mcf. Realized gains or losses from oil and natural gas
hedging activities during the quarter generated a $15.40 loss per bo and a $0.65
loss per mcf, for a 2004 fourth quarter realized hedging loss of $87.3 million,
or $0.85 per mcfe.
Average prices realized during the full-year 2004 (including realized gains or
losses from oil and gas derivatives, but excluding unrealized gains or losses on
such derivatives) were $28.33 per bo and $5.29 per mcf, for a realized gas
equivalent price of $5.23 per mcfe. Chesapeake's average realized pricing
differentials to NYMEX during 2004 were a negative $2.35 per bo and a negative
$0.77 per mcf. Realized gains or losses from oil and natural gas hedging
activities during the year generated a $10.24 loss per bo and a $0.27 loss per
mcf, for a full-year 2004 realized hedging loss of $154.9 million, or $0.43 per
mcfe. This compares to oil and gas hedging gains of $184.0 million realized from
2001-03.
In the past two months, Chesapeake has added to its hedge positions in 2005 and
2006. The following tables compare Chesapeake's projected 2005-06 oil and
natural gas production volumes that have been hedged as of February 22, 2005 to
what had been previously hedged as of December 27, 2004.
HEDGED POSITIONS AS OF FEBRUARY 22, 2005
OIL NATURAL GAS
------------------------------------- ------------------------------------
QUARTER OR YEAR % HEDGED $ NYMEX % HEDGED $ NYMEX
========================== ================= ================ ================= ===============
2005 1Q 53% $41.87 68% $6.82
2005 2Q 61% $42.39 54% $5.98
2005 3Q 15% $38.00 46% $5.96
2005 4Q 9% $32.15 26% $5.87
- -------------------------- ----------------- ---------------- ----------------- ---------------
- -------------------------- ----------------- ---------------- ----------------- ---------------
2005 Total 34% $41.02 48% $6.24
========================== ================= ================ ================= ===============
========================== ================= ================ ================= ===============
2006 - - 9% $6.15
========================== ================= ================ ================= ===============
HEDGED POSITIONS AS OF DECEMBER 27, 2004
OIL NATURAL GAS
------------------------------------- ------------------------------------
QUARTER OR YEAR % HEDGED $ NYMEX % HEDGED $ NYMEX
========================== ================= ================ ================= ===============
2005 1Q 52% $41.76 67% $6.80
2005 2Q 52% $41.63 39% $5.78
2005 3Q 8% $31.16 34% $5.75
2005 4Q 8% $30.62 23% $5.74
- -------------------------- ----------------- ---------------- ----------------- ---------------
- -------------------------- ----------------- ---------------- ----------------- ---------------
2005 Total 30% $40.20 40% $6.17
========================== ================= ================ ================= ===============
========================== ================= ================ ================= ===============
2006 - - 9% $6.15
========================== ================= ================ ================= ===============
Depending on changes in oil and natural gas futures markets and management's
view of underlying oil and natural gas supply and demand trends, Chesapeake may
either increase or decrease its hedging positions at any time in the future
without notice.
The company's initial 2005 first quarter forecast and updated 2005 and 2006
forecasts are attached to this release in an Outlook dated February 22, 2005
labeled as Schedule "A". This Outlook has been changed from the Outlook dated
December 27, 2004 (attached as Schedule "B" for investors' convenience) to
reflect various updated information.
3
KEY OPERATIONAL AND FINANCIAL STATISTICS ARE SUMMARIZED BELOW FOR THE
2004 FOURTH QUARTER AND THE FULL-YEAR 2004
The table below summarizes Chesapeake's key results during the 2004 fourth
quarter and compares them to the 2004 third quarter and the 2003 fourth quarter:
Three Months Ended:
-------------------
12/31/04 9/30/04 12/31/03
-------- ------- --------
Average daily production (in mmcfe) 1,119 1,024 797
Gas as % of total production 90 88 90
Natural gas production (in bcf) 92.2 83.2 66.3
Average realized gas price ($/mcf) (a) 5.50 5.17 5.15
Oil production (in mbbls) 1,792 1,834 1,165
Average realized oil price ($/bo) (a) 28.70 29.15 23.76
Natural gas equivalent production (in bcfe) 102.9 94.2 73.3
Gas equivalent realized price ($/mcfe) (a) 5.42 5.13 5.03
Net marketing income ($/mcfe) .07 .04 .04
General and administrative costs ($/mcfe) (b) (.08) (.09) (.10)
Production taxes ($/mcfe) (.34) (.33) (.28)
Production expenses ($/mcfe) (.55) (.57) (.49)
Interest expense ($/mcfe) (a) (.43) (.45) (.51)
DD&A of oil and gas properties ($/mcfe) (1.67) (1.63) (1.41)
D & A of other assets ($/mcfe) (.09) (.08) (.06)
Operating cash flow ($ in millions) (c) 423.7 353.4 262.4
Operating cash flow ($/mcfe) 4.12 3.75 3.58
Ebitda ($ in millions) (d) 550.1 361.3 257.8
Ebitda ($/mcfe) 5.34 3.83 3.52
Net income to common shareholders ($ in millions) 163.2 85.6 62.4
(a) includes the effects of realized gains or (losses) from hedging,
but does not include the effects of unrealized gains or (losses)
from hedging
(b) excludes expenses associated with non-cash stock-based
compensation
(c) defined as cash flow provided by operating activities before
changes in assets and liabilities
(d) defined as income before income taxes, interest expense, and
depreciation, depletion and amortization expense
In addition, the table below summarizes Chesapeake's key statistics during 2004
and compares them to the prior two years' results:
Year Ended:
-----------
12/31/04 12/31/03 12/31/02
-------- -------- --------
Average daily production (in mmcfe) 991 735 497
Gas as % of total production 89 90 89
Natural gas production (in bcf) 322.0 240.4 160.7
Average realized gas price ($/mcf) (a) 5.29 4.85 3.54
Oil production (in mbbls) 6,764 4,665 3,466
Average realized oil price ($/bbl) (a) 28.33 25.85 25.22
Natural gas equivalent production (in bcfe) 362.6 268.4 181.5
Gas equivalent realized price ($/mcfe) (a) 5.23 4.79 3.61
Net marketing income ($/mcfe) .05 .04 .03
General and administrative costs ($/mcfe) (b) (.09) (.08) (.10)
Production taxes ($/mcfe) (.29) (.29) (.17)
Lease operating expenses ($/mcfe) (.56) (.51) (.54)
Interest expense ($/mcfe) (a) (.45) (.55) (.61)
DD&A of oil and gas properties ($/mcfe) (1.61) (1.38) (1.22)
D & A of other assets ($/mcfe) (.08) (.06) (.08)
Operating cash flow ($ in millions) (c) 1,418.8 903.9 412.5
Operating cash flow ($/mcfe) 3.91 3.37 2.27
Ebitda ($ in millions) (d) 1,583.6 1,041.6 414.4
Ebitda ($/mcfe) 4.37 3.88 2.28
Net income to common shareholders ($ in millions) 439.0 290.5 30.2
(a) includes the effects of realized gains or (losses) from hedging,
but does not include the effects of unrealized gains or (losses)
from hedging
(b) excludes expenses associated with non-cash stock based
compensation
(c) defined as cash flow provided by operating activities before
changes in assets and liabilities
(d) defined as income before income taxes and cumulative effect of
accounting change, interest expense, and depreciation, depletion
and amortization expense
4
COMPANY'S LEASEHOLD AND 3-D SEISMIC INVENTORIES NOW EXCEED 3.3 MILLION AND
9.9 MILLION NET ACRES; IDENTIFIED NON-PROVED RESERVES IN
COMPANY'S EXTENSIVE GAS RESOURCE PLAYS EXCEED 4.0 TCFE
Chesapeake's exploratory and development drilling programs and production
enhancement operations on its existing and acquired properties continue to
produce operational results that exceed the company's forecasts and distinguish
the company among its peers. During 2004, Chesapeake drilled 561 gross (425 net)
operated wells and participated in another 890 gross (121 net) wells operated by
other companies. The company's drilling success rate was 96% for
company-operated wells and 96% for non-operated wells. During the year,
Chesapeake invested $756 million in operated wells (using an average of 56
operated rigs during 2004), $236 million in non-operated wells (using an average
of approximately 65 non-operated rigs during 2004) and $300 million in acquiring
new 3-D seismic data and new leases (exclusive of leases acquired through
acquisitions).
The key to Chesapeake's strong organic growth rates during 2004 and in the past
four years was our early recognition that oil and gas prices were undergoing
structural change. We subsequently reacted by investing more than $1.3 billion
in new leasehold and 3-D seismic acquisitions. In addition, during the past four
years, we have significantly strengthened our technical capabilities by tripling
our land, geoscience and engineering staff to more than 400 employees.
In addition to making significant additions to our existing core leasehold
positions in the Anadarko and Arkoma Basins, South Texas, Texas Gulf Coast and
Permian Basin projects, Chesapeake has also been aggressively building
significant leasehold positions in the following gas resource plays: Sahara in
the northwestern Anadarko Basin (approximately 600,000 prospective net acres
acquired to date), the Mountain Front Deep Springer play in the western and
southern Anadarko Basin (approximately 100,000 prospective net acres acquired to
date), the Granite Wash and Cherokee/Atoka Wash plays in the western Anadarko
Basin (approximately 200,000 prospective net acres acquired to date), the
Hartshorne Coal and the Caney, Woodford and Fayetteville Shale plays of the
Arkoma Basin (approximately 250,000 prospective acres acquired to date), the
Barnett Shale play in North Texas (approximately 30,000 prospective net acres
acquired to date, mainly in northern Johnson County), the Cotton Valley play in
Northern Louisiana's Sligo Field (25,000 prospective net acres acquired to date)
and, most recently, the Haley Deep play in West Texas (approximately 100,000
prospective net acres acquired to date).
Chesapeake believes it has built the largest onshore U.S. inventories of
leasehold and 3-D seismic in the industry (more than 3.3 million and 9.9 million
net acres, respectively) and believes it has identified more than a seven-year
drilling backlog of 7,000 locations on which the company expects to develop more
than 4.0 trillion cubic feet of natural gas equivalent (tcfe) of internally
estimated non-proved reserves.
BALANCE SHEET CONTINUES TO STRENGTHEN IN 2004
As of December 31, 2004, Chesapeake's long-term debt was $3.1 billion and its
stockholders' equity was $3.2 billion, for a debt-to-total capitalization ratio
of 49%, compared to a debt-to-total capitalization ratio of 54% at year-end
2003. At year-end 2004, the company's estimated proved reserves were 4.9 tcfe,
for long-term debt per mcfe of proved reserves of $0.63, compared to $0.65 per
mcfe at year-end 2003. Pro forma for the BRG acquisition that closed on February
1, 2005, Chesapeake's estimated proved reserves were 5.1 tcfe. Given
Chesapeake's strong reserve replacement record through the drillbit, low
operating costs and high returns on invested capital, the company believes that
it will continue to strengthen its balance sheet in the years ahead.
In late January 2005, Chesapeake increased its financial flexibility by amending
its secured revolving bank credit facility to expand the borrowing base and
amount available to $1.25 billion and to extend the maturity to January 2010.
5
MANAGEMENT COMMENTS
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "Today's
announcement of very strong operational and financial results for the fourth
quarter and full-year 2004 provides compelling evidence that Chesapeake's
business strategy continues to create significant shareholder value. Key
measures reflecting this increase in shareholder value are:
o a record level of proved reserves, production, net income to common
shareholders, cash flow and ebitda;
o exceptional organic growth for the 2004fourth quarter and the
full-year 2004, organic growth that we believe is the best performance
among all public mid- and large-cap E&P companies;
o a 9% increase in sequential quarterly production in the 2004 fourth
quarter compared to the 2004 third quarter;
o a 40% increase in year-over-year fourth quarter production;
o a 35% increase in full-year 2004 production over 2003 production;
o a 20% increase in estimated 2005 production over 2004 production;
o an 11% increase in estimated 2006 production over estimated 2005
production;
o reserve replacement for the year of 578% at a drilling and acquisition
cost of $1.21 per mcfe;
o excellent operating cost control and high returns on equity and total
capital; and
o a seven-year inventory of drilling projects with estimated development
potential of at least 4.0 tcfe of estimated non-proved reserves in the
years ahead.
The company's business strategy has worked very well for our shareholders since
our IPO on February 4, 1993, generating an approximate 1,400% increase in our
common stock price during the past 12 years. Our business strategy features
delivering growth through a balance of acquisitions and organic drilling,
focusing on natural gas to take advantage of strong long-term natural gas
supply/demand fundamentals and building dominant regional scale to achieve low
operating costs and high returns on capital. We believe Chesapeake's management
team can continue the successful execution of the company's distinctive business
strategy and continue to deliver significant shareholder value for years to
come."
CONFERENCE CALL INFORMATION
A conference call has been scheduled for Wednesday morning, February 23, 2005 at
9:00 a.m. EST to discuss this earnings release. The telephone number to access
the conference call is 913.981.5520. For those unable to participate in the
conference call, a replay will be available from 12:00 p.m. EST, February 23,
2005 through midnight EST on February 27, 2005. The number to access the
conference call replay is 719.457.0820 and the passcode is 9640052. 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.
6
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 EXCHANGE OFFER PROSPECTUS
DATED NOVEMBER 30, 2004 (AS AMENDED ON DECEMBER 16, 2004) FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION ON DECEMBER 20, 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.
CHESAPEAKE ENERGY CORPORATION IS THE FOURTH LARGEST INDEPENDENT PRODUCER OF
NATURAL GAS IN THE U.S. HEADQUARTERED IN OKLAHOMA CITY, THE COMPANY'S OPERATIONS
ARE FOCUSED ON EXPLORATORY AND DEVELOPMENTAL DRILLING AND 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.
7
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
========================================================================================================================
THREE MONTHS ENDED: December 31, 2004 December 31, 2003
$ $/mcfe $ $/mcfe
----------- ---------- ------------ ---------
REVENUES:
Oil and gas sales 665,782 6.47 345,697 4.72
Oil and gas marketing sales 276,269 2.68 111,044 1.51
-------- -------- --------- -------
Total Revenues 942,051 9.15 456,741 6.23
-------- -------- --------- -------
OPERATING COSTS:
Production expenses 56,321 0.55 35,919 0.49
Production taxes 35,372 0.34 20,557 0.28
General and administrative expenses:
General and administrative (excluding stock-based
compensation) 8,270 0.08 7,068 0.09
Stock-based compensation 1,703 0.02 433 0.01
Oil and gas marketing expenses 269,109 2.61 108,224 1.48
Oil and gas depreciation, depletion, and amortization 171,900 1.67 103,334 1.41
Depreciation and amortization of other assets 9,030 0.09 4,146 0.06
Provision for legal settlements 4,500 0.04 5,400 0.07
-------- -------- --------- -------
Total Operating Costs 556,205 5.40 285,081 3.89
-------- -------- --------- -------
INCOME FROM OPERATIONS 385,846 3.75 171,660 2.34
-------- -------- --------- --------
OTHER INCOME (EXPENSE):
Interest and other income 913 0.01 1,471 0.02
Interest expense (43,288) (0.42) (38,465) (0.52)
Loss on repurchases or exchanges of Chesapeake debt (17,632) (0.17) (20,759) (0.28)
Loss on investment in Seven Seas -- -- (2,015) (0.03)
-------- -------- --------- --------
Total Other Income (Expense) (60,007) (0.58) (59,768) (0.81)
-------- -------- --------- --------
Income Before Income Taxes 325,839 3.17 111,892 1.53
Income Tax Expense:
Current -- -- 4,670 0.06
Deferred 117,301 1.14 37,849 0.52
-------- -------- --------- --------
Total Income Tax Expense 117,301 1.14 42,519 0.58
NET INCOME 208,538 2.03 69,373 0.95
-------- -------- --------- --------
Preferred stock dividends (8,707) (0.08) (6,985) (0.10)
Loss on conversion/exchange of preferred stock (36,678) (0.36) -- --
-------- -------- --------- --------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS 163,153 1.59 62,388 0.85
======== ======== ========= ========
- ------------------------------------------------------------------------------------------------------------------------
EARNINGS PER COMMON SHARE:
Basic $ 0.59 $ 0.29
======== ========
Assuming dilution $ 0.52 $ 0.25
======== ========
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in 000's):
Basic 277,410 216,571
======== ========
Assuming dilution 328,029 273,169
======== ========
8
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
========================================================================================================================
TWELVE MONTHS ENDED: December 31, 2004 December 31, 2003
$ $/mcfe $ $/mcfe
------------- ----------- ----------- ----------
REVENUES:
Oil and gas sales 1,936,176 5.34 1,296,822 4.83
Oil and gas marketing sales 773,092 2.13 420,610 1.57
--------- -------- --------- -------
Total Revenues 2,709,268 7.47 1,717,432 6.40
--------- -------- --------- -------
OPERATING COSTS:
Production expenses 204,821 0.56 137,583 0.51
Production taxes 103,931 0.29 77,893 0.29
General and administrative expenses:
General and administrative (excluding stock-based
compensation) 32,217 0.09 22,808 0.09
Stock-based compensation 4,828 0.01 945 --
Oil and gas marketing expenses 755,314 2.08 410,288 1.53
Oil and gas depreciation, depletion, and amortization 582,137 1.61 369,465 1.38
Depreciation and amortization of other assets 29,185 0.08 16,793 0.06
Provision for legal settlements 4,500 0.01 6,402 0.02
--------- -------- --------- --------
Total Operating Costs 1,716,933 4.73 1,042,177 3.88
--------- -------- --------- --------
INCOME FROM OPERATIONS 992,335 2.74 675,255 2.52
--------- -------- --------- --------
OTHER INCOME (EXPENSE):
Interest and other income 4,476 0.01 2,827 0.01
Interest expense (167,328) (0.46) (154,356) (0.57)
Loss on repurchases or exchanges of Chesapeake debt (24,557) (0.07) (20,759) (0.08)
Loss on investment in Seven Seas -- -- (2,015) (0.01)
-------- -------- --------- --------
Total Other Income (Expense) (187,409) (0.52) (174,303) (0.65)
-------- -------- --------- --------
Income Before Income Taxes and Cumulative Effect
of Accounting Change 804,926 2.22 500,952 1.87
Income Tax Expense:
Current -- -- 5,000 0.02
Deferred 289,771 0.80 185,360 0.69
-------- -------- -------- --------- -------
Total Income Tax Expense 289,771 0.80 190,360 0.71
------------------------ -------- -------- --------- -------
NET INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE, NET OF TAX 515,155 1.42 310,592 1.16
-------- -------- -------- --------
Cumulative Effect of Accounting Change, Net of
Income Tax of $1,464,000 -- -- 2,389 0.01
-------- -------- -------- --------
NET INCOME 515,155 1.42 312,981 1.17
Preferred stock dividends (39,506) (0.11) (22,469) (0.09)
Loss on conversion/exchange of preferred stock (36,678) (0.10) -- --
-------- -------- --------- --------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
438,971 1.21 290,512 1.08
======== ======== ========= ========
- ------------------------------------------------------------------------------------------------------------------------
EARNINGS PER COMMON SHARE:
Basic
Income Before Cumulative Effect of Accounting Change $ 1.73 $ 1.36
Cumulative Effect of Accounting Change -- 0.02
-------- --------
Net Income $ 1.73 $ 1.38
======== ========
Assuming dilution
Income Before Cumulative Effect of Accounting Change $ 1.53 $ 1.20
Cumulative Effect of Accounting Change -- 0.01
-------- --------
Net Income $ 1.53 $ 1.21
======== ========
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING (in 000's):
Basic 253,212 211,203
======= =========
Assuming dilution 305,718 258,567
======= =========
9
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in 000's)
(unaudited)
=======================================================================================================================
December 31, December 31,
2004 2003
- -----------------------------------------------------------------------------------------------------------------------
Cash $ 6,896 $ 40,581
Other current assets 560,644 301,823
------------- -------------
CURRENT ASSETS 567,540 342,404
------------- --------------
Property and equipment (net) 7,444,384 4,133,117
Other assets 232,585 96,770
------------- --------------
TOTAL ASSETS $8,244,509 $ 4,572,291
============= ==============
Current liabilities $ 963,953 $ 513,156
Long term debt 3,075,109 2,057,713
Asset retirement obligation 73,718 48,812
Long term liabilities 34,973 28,774
Deferred tax liability 933,873 191,026
------------- --------------
TOTAL LIABILITIES 5,081,626 2,839,481
STOCKHOLDERS' EQUITY 3,162,883 1,732,810
------------- --------------
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY $ 8,244,509 $ 4,572,291
============= ==============
COMMON SHARES OUTSTANDING 311,869 216,784
============= ==============
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF 2004 COSTS INCURRED
($ in 000's, except per unit amounts)
(unaudited)
========================================================================================================
Reserves
Cost (in mmcfe) Per Unit
------------- ---------- --------
Exploration and development costs (a) $ 991,903 962,246 1.03
Acquisition of proved properties 1,541,920 1,137,463 1.36
Subtotal 2,533,823 2,099,709 1.21
Acquisition of unproved properties 570,495 -- --
Divestitures (12,048) (3,940) (3.06)
Leasehold acquisition costs 110,530 -- --
Geological and geophysical costs 55,618 -- --
Adjusted subtotal 3,258,418 2,095,769 1.55
Tax basis step-up 463,949 -- --
Asset retirement obligation and other 41,924 -- --
Total $ 3,764,291 2,095,769 1.80
(a) Reserves include revisions to previous estimates
CHESAPEAKE ENERGY CORPORATION
ROLLFORWARD OF RESERVES
(unaudited)
=======================================================================
Mmcfe
-----------------------------------------------------------------------
Beginning balance, 12/31/03 3,168,575
Production (362,593)
Acquisitions 1,137,463
Divestitures (3,940)
Revisions-performance 140,568
Revisions-price 4,950
Extensions and discoveries 816,728
Ending balance, 12/31/04 4,901,751
Reserve replacement 2,095,769
Reserve replacement rate 578%
=======================================================================
10
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE
Three Months Ended Twelve Months Ended
------------------------------- -------------------------------
December 31, December 31,
------------------------------- -------------------------------
2004 2003 2004 2003
-------------- -------------- -------------- ---------------
Oil and Gas Sales ($ in thousands):
Oil sales $ 79,033 $ 30,819 $ 260,915 $ 132,630
Oil derivatives - realized gains (losses) (27,595) (3,134) (69,267) (12,058)
Oil derivatives - unrealized gains (losses) 25,379 (8,447) 3,454 (9,440)
---------- --------- ---------- ----------
Total oil sales
$ 76,817 $ 19,238 $ 195,102 $ 111,132
---------- --------- ---------- -----------
Gas sales $ 566,492 $ 281,452 1,789,275 $ 1,171,050
Gas derivatives - realized gains (losses) (59,658) 59,697 (85,634) (5,331)
Gas derivatives - unrealized gains (losses) 82,131 (14,690) 37,433 19,971
---------- --------- ---------- ----------
Total gas sales $ 588,965 $ 326,459 $1,741,074 1,185,690
---------- --------- ---------- ---------
Total oil and gas sales $ 665,782 $ 345,697 $1,936,176 $1,296,822
========== ========= ========== ==========
Average Sales Price (excluding gains (losses) on
derivatives):
Oil ($ per bbl) $ 44.10 $ 26.45 $ 38.57 $ 28.43
Gas ($ per mcf) $ 6.15 $ 4.25 $ 5.56 $ 4.87
Gas equivalent ($ per mcfe) $ 6.27 $ 4.26 $ 5.65 $ 4.86
Average Sales Price (excluding unrealized gains (losses) on
derivatives):
Oil ($ per bbl) $ 28.70 $ 23.76 $ 28.33 $ 25.85
Gas ($ per mcf) $ 5.50 $ 5.15 $ 5.29 $ 4.85
Gas equivalent ($ per mcfe) $ 5.42 $ 5.03 $ 5.23 $ 4.79
Interest Expense ($ in thousands):
Interest $ (44,446) $ (38,665) $ (162,781) (151,676)
Derivatives - realized (gains) losses 607 1,406 791 3,859
Derivatives - unrealized (gains) losses 551 (1,206) (5,338) (6,539)
---------- --------- ---------- -----------
Total Interest Expense $ (43,288) $ (38,465) $ (167,328) $ (154,356)
========== ========= ========== ===========
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
(in 000's)
(unaudited)
===============================================================================================
THREE MONTHS ENDED: December 31, December 31,
2004 2003
-----------------------------------------------------------------------------------------------
Cash provided by operating activities $ 410,349 $ 292,085
Cash (used in) investing activities (712,963) (476,449)
Cash provided by financing activities 260,437 186,467
===============================================================================================
===============================================================================================
TWELVE MONTHS ENDED: December 31, December 31,
2004 2003
-----------------------------------------------------------------------------------------------
Cash provided by operating activities $1,448,555 $ 945,602
Cash (used in) investing activities (3,381,204) (2,077,217)
Cash provided by financing activities 1,898,964 924,559
===============================================================================================
11
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF CERTAIN FINANCIAL MEASURES
(in 000's)
(unaudited)
===================================================================================================
THREE MONTHS ENDED: December 31, December 31,
2004 2003
---------------------------------------------------------------------------------------------------
CASH PROVIDED BY OPERATING ACTIVITIES $ 410,349 $ 292,085
Adjustments:
Changes in assets and liabilities 13,330 (29,647)
------------- ------------
OPERATING CASH FLOW* $ 423,679 $ 262,438
*Operating cash flow represents net cash provided by operating activities before
changes in assets and liabilities. Operating cash flow is presented because
management believes it is a useful adjunct to net cash provided by operating
activities under accounting principles generally accepted in the United States
(GAAP). Operating cash flow is widely accepted as a financial indicator of an
oil and gas company's ability to generate cash which is used to internally fund
exploration and development activities and to service debt. This measure is
widely used by investors and rating agencies in the valuation, comparison,
rating and investment recommendations of companies within the oil and gas
exploration and production industry. Operating cash flow is not a measure of
financial performance under GAAP and should not be considered as an alternative
to cash flows from operating, investing, or financing activities as an indicator
of cash flows, or as a measure of liquidity.
==================================================================================================
THREE MONTHS ENDED: December 31, December 31,
2004 2003
--------------------------------------------------------------------------------------------------
Net income $ 208,538 $ 69,373
Income tax expense 117,301 42,519
Interest expense 43,288 38,465
Depreciation and amortization of other assets 9,030 4,146
Oil and gas depreciation, depletion and amortization 171,900 103,334
--------------- ------------
EBITDA** $ 550,057 $ 257,837
**Ebitda represents net income (loss) before cumulative effect of accounting
change, income tax expense (benefit), interest expense, and depreciation,
depletion and amortization expense. Ebitda is presented as a supplemental
financial measurement in the evaluation of our business. We believe that it
provides additional information regarding our ability to meet our future debt
service, capital expenditures and working capital requirements. This measure is
widely used by investors and rating agencies in the valuation, comparison,
rating and investment recommendations of companies. Ebitda is also a financial
measurement that, with certain negotiated adjustments, is reported to our
lenders pursuant to our bank credit agreement and is used in the financial
covenants in our bank credit agreement and our senior note indentures. Ebitda is
not a measure of financial performance under GAAP. Accordingly, it should not be
considered as a substitute for net income, income from operations, or cash flow
provided by operating activities prepared in accordance with GAAP. Ebitda is
reconciled to cash provided by operating activities as follows:
===============================================================================================
THREE MONTHS ENDED: December 31, December 31,
2004 2003
-----------------------------------------------------------------------------------------------
CASH PROVIDED BY OPERATING ACTIVITIES $ 410,349 $ 292,085
Changes in assets and liabilities 13,330 (29,647)
Interest expense 43,288 36,465
Unrealized gains (losses) on oil and gas derivatives 107,510 (23,137)
Other non-cash items (24,420) (19,929)
------------ ------- -----
EBITDA $ 550,057 $ 257,837
12
===============================================================================================
TWELVE MONTHS ENDED: December 31, December 31,
2004 2003
-----------------------------------------------------------------------------------------------
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,448,555 $ 945,602
Adjustments:
Changes in assets and liabilities (29,752) (41,673)
------- --- -----------
OPERATING CASH FLOW* $ 1,418,803 $ 903,929
=========== ===========
*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.
===============================================================================================
TWELVE MONTHS ENDED: December 31, December 31,
2004 2003
-----------------------------------------------------------------------------------------------
Net income before cumulative effect of accounting change $ 515,155 $ 310,592
Income tax expense 289,771 190,360
Interest expense 167,328 154,356
Depreciation and amortization of other assets 29,185 16,793
Oil and gas depreciation, depletion and amortization 582,137 369,465
----------- -----------
EBITDA** $ 1,583,576 $ 1,041,566
**Ebitda represents net income (loss) before cumulative effect of accounting
change, income tax expense (benefit), interest expense, and depreciation,
depletion and amortization expense. Ebitda is presented as a supplemental
financial measurement in the evaluation of our business. We believe that it
provides additional information regarding our ability to meet our future debt
service, capital expenditures and working capital requirements. This measure is
widely used by investors and rating agencies in the valuation, comparison,
rating and investment recommendations of companies. Ebitda is also a financial
measurement that, with certain negotiated adjustments, is reported to our
lenders pursuant to our bank credit agreement and is used in the financial
covenants in our bank credit agreement and our senior note indentures. Ebitda is
not a measure of financial performance under GAAP. Accordingly, it should not be
considered as a substitute for net income, income from operations, or cash flow
provided by operating activities prepared in accordance with GAAP. Ebitda is
reconciled to cash provided by operating activities as follows:
===============================================================================================
TWELVE MONTHS ENDED: December 31, December 31,
2004 2003
-----------------------------------------------------------------------------------------------
CASH PROVIDED BY OPERATING ACTIVITIES $ 1,448,555 $ 945,602
Changes in assets and liabilities (29,752) (41,673)
Interest expense 167,328 154,356
Unrealized gains (losses) on oil and gas derivatives 40,887 10,531
Other non-cash items (43,442) (27,250)
----------- ------------
EBITDA** $ 1,583,576 $ 1,041,566
13
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EARNINGS & ADJUSTED EBITDA
($ In 000's, except per share amounts)
===============================================================================================
Three Months Ended Twelve Months Ended
December 31, 2004 December 31, 2004
-----------------------------------------------------------------------------------------------
Net income available to common shareholders $ 163,153 $ 438,971
Adjustments:
Preferred stock dividends 8,707 39,506
Loss on conversion/exchange of preferred stock** 36,678 36,678
Net income $ 208,538 $ 515,155
Adjustments, net of tax:
Unrealized (gains) losses on derivatives (69,159) (22,751)
Loss on repurchases or exchanges of debt 11,284 15,716
Provision for legal settlements 2,880 2,880
Adjusted earnings* $ 153,543 $ 511,000
Adjusted earnings per share assuming dilution** $ 0.44 $ 1.56
EBITDA $ 550,057 $ 1,583,576
Adjustments, before tax:
Unrealized (gains) losses on oil and gas (107,510) (40,887)
derivatives
Loss on repurchases or exchanges of debt 17,632 24,557
Provision for legal settlements 4,500 4,500
Adjusted EBITDA* $ 464.679 $ 1,571,746
*Adjusted earnings and adjusted earnings per share assuming dilution and
adjusted EBITDA, 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.
**For purposes of calculating fully diluted shares and earnings per share
assuming dilution for the fourth quarter and full-year 2004, accounting rules
prohibit the company from assuming the conversion of the 6.0% preferred stock
for common shares prior to conversion or exchange for either period since the
effect would have been anti-dilutive. In determining adjusted earnings per
share, we have reflected the converted shares as though they were converted at
the beginning of the period (fully diluted share count of 347.8 million for the
fourth quarter and 327.1 million for the full-year).
14
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF FEBRUARY 22, 2005
Quarter Ending March 31, 2005; Year Ending December 31, 2005; Year Ending
December 31, 2006.
We have adopted a policy of periodically providing investors with guidance on
certain factors that affect our future financial performance. As of February 22,
2005, we are using the following key assumptions in our projections for the
first quarter of 2005, the full-year 2005 and the full-year 2006.
The primary changes from our December 27, 2004 Outlook are in italicized bold in
the table and are explained as follows:
1) We have provided our first production forecast for the first quarter of
2005.
2) We have increased capital expenditures by $100 million in 2005 and $50
million in 2006 to reflect a planned increase in drilling activity on
various company properties.
3) We have updated the projected effects from changes in our hedging positions
since our December 27, 2004 Outlook.
4) We have included our expectations for future NYMEX oil and gas prices to
illustrate hedging effects only.
Quarter Ending Year Ending Year Ending
March 31, 2005 December 31, 2005 December 31, 2006
-------------- ----------------- -----------------
Estimated Production:
Oil - Mbo 1,650 6,600 6,600
Gas - Bcf 91 - 92 391 - 399 438 - 448
Gas Equivalent - Bcfe 101 - 102 430 - 438 478 - 488
Daily gas equivalent midpoint -in Mmcfe 1,128 1,190 1,325
NYMEX Prices
(for calculation of realized hedging effects only):
Oil - $/Bo $42.28 $40.57 $40.00
Gas - $/Mcf $6.17 $6.04 $6.00
Estimated Differentials to NYMEX Prices:
Oil - $/Bo -$2.75 -$2.75 -$2.75
Gas - $/Mcf -$0.75 -$0.70 -$0.70
Estimated Realized Hedging Effects
(based on expected NYMEX prices above):
Oil - $/Bo -$0.23 $0.04 $0.00
Gas - $/Mcf $0.56 $0.07 $0.00
Operating Costs per Mcfe of Projected Production:
Production expense $0.62 - 0.67 $0.62 - 0.67 $0.68 - 0.72
Production taxes (generally 7% of O&G revenues) $0.38 - 0.40 $0.38 - 0.40 $0.38 - 0.40
General and administrative $0.10 - 0.11 $0.10 - 0.11 $0.11 - 0.12
Stock-based compensation (non-cash) $0.02 - 0.04 $0.04 - 0.06 $0.09 - 0.10
DD&A - oil and gas $1.70 - 1.75 $1.75 - 1.80 $1.80 - 1.90
Depreciation of other assets $0.09 - 0.11 $0.09 - 0.11 $0.10 - 0.12
Interest expense(a) $0.43 - 0.47 $0.43 - 0.47 $0.43 - 0.47
Other Income and Expense per Mcfe:
Marketing and other income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04
Book Tax Rate 36.5% 36.5% 36.5%
Equivalent Shares Outstanding:
Basic 314 mm 315 mm 318 mm
Diluted 352 mm 352 mm 355 mm
Capital Expenditures:
Drilling, leasehold and seismic $350 - $375 $1,400 - $1,500 $1,500 -
mm mm $1,600 mm
(a) Does not include gains or losses on interest rate derivatives (SFAS 133).
15
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. 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
-------- ------- ---------- ---------- ------------- ----------
2005:
1st Qtr 62.2 $7.00 -$0.18 $6.82 91.5 68%
2nd Qtr 52.2 $6.17 -$0.19 $5.98 97.0 54%
3rd Qtr 46.4 $6.19 -$0.23 $5.96 101.5 46%
4th Qtr 27.5 $6.26 -$0.39 $5.87 105.0 26%
=============================================================================================
Total 2005(1) 188.3 $6.46 -$0.22 $6.24 395.0 48%
=============================================================================================
=============================================================================================
Total 2006(1) 39.3 $6.77 -$0.62 $6.15 443.0 9%
=============================================================================================
=============================================================================================
Total 2007(2) - - - - 470.0 -
=============================================================================================
=============================================================================================
TOTALS
- ---------------------------------------------------------------------------------------------
2005-2007 227.6 $6.51 -$0.29 $6.22 1,308.0 17%
=============================================================================================
(1) Certain hedging arrangements include swaps with knockout prices ranging
from $3.75 to $5.50 covering 70.0 bcf in 2005 and $3.75 to $5.50 covering
28.4 bcf in 2006.
(2) Swaps covering 25.6 bcf have been locked for 2007. This will result in the
recognition of $11.6 million of losses in 2007 when the hedging
arrangements settle.
Note: Not shown above are collars covering 4.4 bcf of production in 2005 at a
weighted average floor and ceiling of $3.10 and $4.44. and call options covering
7.3 bcf of production in 2005 at a weighted average price of $6.00.
16
The company has also entered into the following natural gas basis protection
swaps:
Assuming Gas
Volume in Bcf's NYMEX less: Production in Bcf's %Hedged
---------------- ---------------- ------------------- -------
2005 188.6 0.26 392.0 48%
2006 130.1 0.32 440.0 30%
2007 126.5 0.28 470.0 27%
2008 118.6 0.27 495.0 24%
2009 86.6 0.29 520.0 17%
Totals 650.4 $ 0.28 2,317.0 28%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
----------------------------------------------------------------
Open Swaps Avg. NYMEX Assuming Oil Open Swap Positions as %
in mbo's Strike Price Production in mbo's of: of Total Estimated Production
-------- ------------ ----------------------- -----------------------------
Q1 - 2005 870.5 $41.87 1,650 53%
Q2 - 2005 1,001.0 $42.39 1,650 61%
Q3 - 2005 246.0 $38.00 1,650 15%
Q4 - 2005 153.5 $32.15 1,650 9%
- ----------------------------------------------------------------------------------------------------------------
Total 2005(1) 2,271.0 $41.02 6,600 34%
===============================================================================================
(1) Certain hedging arrangements include swaps with knockout prices ranging
from $26.00 to $34.00 covering 1,996 mbo in 2005.
17
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF DECEMBER 27, 2004
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF FEBRUARY 22, 2005
Quarter Ending December 31, 2004; Year Ending December 31, 2004; Year Ending
December 31, 2005; Year Ending December 31, 2006.
We have adopted a policy of periodically providing investors with guidance on
certain factors that affect our future financial performance. As of December 27,
2004, we are using the following key assumptions in our projections for the
fourth quarter of 2004, the full-year 2004, the full-year 2005 and the full-year
2006.
We expect to record non-operating losses in Q4 2004 in connection with our
pending cash tender offer for our $209.8 million of 8.375% senior notes due 2008
and our pending offer to exchange our 6.0% convertible preferred stock for our
common stock. If we purchase all of our 8.375% senior notes pursuant to the
tender offer, we estimate that an after-tax loss on the early redemption of the
notes of $12 million will be recorded in Q4 2004 as an adjustment to net
earnings. If all our 6.0% preferred stock is exchanged for common stock, we
estimate that a loss on the early conversion of the preferred stock of
approximately $37 million will be reflected as an adjustment to net income
available to common shareholders for the purpose of calculating basic earnings
per share in Q4 2004.
The primary changes from our November 30, 2004 Outlook are in italicized bold in
the table and are explained as follows:
1) We have updated our previous production forecasts for 2005 and 2006 to
reflect increases in production of 35 mmcfe per day in 2005 (excluding
January) and 55 mmcfe per day in 2006 as a result of the announced
acquisition of BRG Petroleum Corporation. This increases our full-year 2005
production forecast by 2.8% to a mid-point of 1,190 mmcfe per day and our
2006 production forecast by 4.3% to a mid-point of 1,325 mmcfe per day.
2) We have increased capital expenditures by $50 million in 2005 and $100
million in 2006 to reflect planned increased drilling activity planned on
the BRG and other company properties.
3) We have updated the projected effects from changes in our hedging positions
since our November 30, 2004 Outlook.
4) We have included our expectations for future NYMEX oil and gas prices to
illustrate hedging effects only.
Quarter Ending Year Ending Year Ending Year Ending
December 31, December 31, December 31, December 31,
------------ ------------ ------------ ------------
2004 2004 2005 2006
---- ---- ---- ----
Estimated Production:
Oil - Mbo 1,588 6,560 6,600 6,600
Gas - Bcf 88.5 - 89.5 317 - 319 391 - 399 438 - 448
Gas Equivalent - Bcfe 98 - 99 356 - 358 430 - 438 478 - 488
Daily gas equivalent midpoint -in Mmcfe 1,069 975 1,190 1,325
NYMEX Prices
(for calculation of realized hedging effects only):
Oil - $/Bo $46.67 $41.00 $40.00 $40.00
Gas - $/Mcf $6.60 $6.01 $6.00 $6.00
Estimated Differentials to NYMEX Prices:
Oil - $/Bo -$2.75 -$2.65 -$2.75 -$2.75
Gas - $/Mcf -$0.75 -$0.70 -$0.70 -$0.70
Estimated Realized Hedging Effects
(based on expected NYMEX prices above):
Oil - $/Bo -$15.85 -$10.19 $0.06 $0.00
Gas - $/Mcf -$0.53 -$0.23 $0.05 -$0.01
Operating Costs per Mcfe of Projected Production:
Production expense $0.57 - 0.62 $0.57 - 0.62 $0.62 - 0.67 $0.68 - 0.72
Production taxes (generally 7% of O&G revenues) $0.40 - 0.44 $0.28 - 0.33 $0.38 - 0.40 $0.38 - 0.40
General and administrative $0.10 - 0.11 $0.10 - 0.11 $0.10 - 0.11 $0.11 - 0.12
Stock based compensation (non-cash) $0.02 - 0.04 $0.02 - 0.04 $0.04 - 0.06 $0.09 - 0.10
DD&A - oil and gas $1.65 - 1.70 $1.60 - 1.65 $1.75 - 1.80 $1.80 - 1.90
Depreciation of other assets $0.08 - 0.10 $0.08 - 0.10 $0.09 - 0.11 $0.10 - 0.12
Interest expense(a) $0.45 - 0.49 $0.45 - 0.49 $0.43 - 0.47 $0.43 - 0.47
Other Income and Expense per Mcfe:
Marketing and other income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04
Book Tax Rate 36% 36% 36% 36%
Equivalent Shares Outstanding:
Basic 279 mm 254 mm 313 mm 316 mm
Diluted 347 mm 327 mm 351 mm 354 mm
Capital Expenditures:
Drilling, leasehold and seismic $300 - $325 $1,100 - $1,150 $1,300 - $1,450 - $1,550
mm mm $1,400 mm mm
(b) Does not include gains or losses on interest rate derivatives (SFAS 133).
18
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. 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) 70.7 $5.49 -$0.09 $5.40 83.2 85%
4th Qtr(1) 76.5 $5.88 -$0.11 $5.77 89.0 86%
- ---------------------------------------------------------------------------------------------
Total 2004 278.9 $5.63 -$0.05 $5.58 318.8 88%
=============================================================================================
=============================================================================================
2005:
1st Qtr 62.4 $6.91 -$0.11 $6.80 93.4 67%
2nd Qtr 38.5 $6.05 -$0.27 $5.78 97.5 39%
3rd Qtr 34.5 $6.06 -$0.31 $5.75 100.8 34%
4th Qtr 23.5 $6.20 -$0.46 $5.74 103.0 23%
=============================================================================================
Total 2005(1) 158.9 $6.41 -$0.24 $6.17 394.7 40%
=============================================================================================
=============================================================================================
Total 2006(1) 39.3 $6.77 -$0.62 $6.15 443.0 9%
=============================================================================================
=============================================================================================
Total 2007(2) - - - - 470.0 -
=============================================================================================
TOTALS
- ---------------------------------------------------------------------------------------------
2005-2007 198.2 $6.48 -$0.31 $6.17 1,307.7 15%
=============================================================================================
(3) Certain hedging arrangements include swaps with knockout prices ranging
from $3.50 to $5.25 covering 25.4 bcf in 2004, $3.75 to $5.50 covering 60.2
bcf in 2005 and $3.75 to $5.50 covering 28.4 bcf in 2006.
(4) Swaps covering 25.6 bcf have been locked for 2007. This will result in the
recognition of $11.6 million of losses in 2007 when the hedging
arrangements settle.
Note: Not shown above are collars covering 1.1 bcf and 4.4 bcf of production in
Q4 2004 and in 2005, respectively, at a weighted average floor and ceiling of
$3.10 and $4.44. In addition, call options covering 10.2 bcf and 7.3 bcf of
production in Q4 2004 and in 2005 at a weighted average price of $6.31 and $6.00
are not included in the table above.
19
The company has also entered into the following natural gas basis protection
swaps:
Assuming Gas
Volume in Bcf's NYMEX less: Production in Bcf's %Hedged
---------------- ---------------- ------------------- -------
2004 157.4 0.17 318.8 49%
2005 188.6 0.26 394.7 48%
2006 130.1 0.32 443.0 29%
2007 126.5 0.28 470.0 27%
2008 118.6 0.27 495.0 24%
2009 86.6 0.29 520.0 17%
Totals 807.8 $ 0.26 2,641.5 31%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
----------------------------------------------------------------
Open Swaps Avg. NYMEX Assuming Oil Open Swap Positions as %
in mbo's Strike Price Production in mbo's of: of Total Estimated 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 1,834 83%
Q4 - 2004(1) 1,518 $30.10 1,588 96%
- ----------------------------------------------------------------------------------------------------------------
Total 2004(1) 5,847 $29.80 6,560 89%
===============================================================================================
Q1 - 2005 855 $41.76 1,650 52%
Q2 - 2005 865 $41.63 1,650 52%
Q3 - 2005 138 $31.16 1,650 8%
Q4 - 2005 138 $30.62 1,650 8%
- ----------------------------------------------------------------------------------------------------------------
Total 2005(1) 1,996 $40.20 6,600 30%
===============================================================================================
(1) Certain hedging arrangements include swaps with knockout prices ranging
from $21.00 to $26.00 covering 2,240 mbo in 2004 and knockout prices
ranging from $26.00 to $34.00 covering 1,996 mbo in 2005.
20