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, Feb. 22 /PRNewswire-FirstCall/ -- 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:
* 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;
* 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;
* a $2.9 million loss for the fourth quarter and for the full year
related to the settlement of certain litigation; and
* 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%.
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, or 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% $6.15
Depending on changes in oil and natural gas futures markets and
management's view of underlying oil and natural gas supply and demand trends,
Chesapeake may either increase or decrease its hedging positions at any time
in the future without notice.
The company's initial 2005 first quarter forecast and updated 2005 and
2006 forecasts are attached to this release in an Outlook dated February 22,
2005 labeled as Schedule "A". This Outlook has been changed from the Outlook
dated December 27, 2004 (attached as Schedule "B" for investors' convenience)
to reflect various updated information.
Key Operational and Financial Statistics are Summarized Below for the 2004
Fourth Quarter and the Full-Year 2004
The table below summarizes Chesapeake's key results during the 2004 fourth
quarter and compares them to the 2004 third quarter and the 2003 fourth
quarter:
Three Months Ended:
12/31/04 9/30/04 12/31/03
Average daily production (in mmcfe) 1,119 1,024 797
Gas as % of total production 90 88 90
Natural gas production (in bcf) 92.2 83.2 66.3
Average realized gas price ($/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
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.
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:
* a record level of proved reserves, production, net income to common
shareholders, cash flow and ebitda;
* exceptional organic growth for the 2004 fourth 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;
* a 9% increase in sequential quarterly production in the 2004 fourth
quarter compared to the 2004 third quarter;
* a 40% increase in year-over-year fourth quarter production;
* a 35% increase in full-year 2004 production over 2003 production;
* a 20% increase in estimated 2005 production over 2004 production;
* an 11% increase in estimated 2006 production over estimated 2005
production;
* reserve replacement for the year of 578% at a drilling and acquisition
cost of $1.21 per mcfe;
* excellent operating cost control and high returns on equity and total
capital; and
* 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 March 8, 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 http://www.chkenergy.com by selecting "Conference Calls" under the
"Investor Relations" section. The webcast of the conference call will be
available on the website for one year.
This press release and the accompanying Outlooks include "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933
and Section 21E of the Securities Exchange Act of 1934. Forward-looking
statements give our current expectations or forecasts of future events. They
include estimates of oil and gas reserves, expected oil and gas production and
future expenses, projections of future oil and gas prices, planned capital
expenditures for drilling, leasehold acquisitions and seismic data, and
statements concerning anticipated cash flow and liquidity, business strategy
and other plans and objectives for future operations. Disclosures concerning
derivative contracts and their estimated contribution to our future results of
operations are based upon market information as of a specific date. These
market prices are subject to significant volatility.
Factors that could cause actual results to differ materially from expected
results are described under "Risk Factors" in our 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 http://www.chkenergy.com .
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 $0.25
WEIGHTED AVERAGE COMMON AND
COMMON EQUIVALENT SHARES
OUTSTANDING (in 000's):
Basic 277,410 216,571
Assuming dilution 328,029 273,169
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ 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
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
TOTAL 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 $3,764,291 2,095,769 1.80
(A) Reserves include revisions to previous estimates
CHESAPEAKE ENERGY CORPORATION
ROLLFORWARD OF RESERVES
(unaudited)
Mmcfe
Beginning balance, 12/31/03 3,168,575
Production (362,593)
Acquisitions 1,137,463
Divestitures (3,940)
Revisions-performance 140,568
Revisions-price 4,950
Extensions and discoveries 816,728
Ending balance, 12/31/04 4,901,751
Reserve replacement 2,095,769
Reserve replacement rate 578%
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL & GAS SALES AND INTEREST EXPENSE
Three Months Ended Twelve Months Ended
December 31, December 31,
2004 2003 2004 2003
Oil and Gas Sales ($ 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
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 38,465
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
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 $1,041,566
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EARNINGS & ADJUSTED EBITDA
($ 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 derivatives (107,510) (40,887)
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).
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 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, December 31, December 31,
2005 2005 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-$1,600
mm mm mm
(A) Does not include gains or losses on interest rate derivatives
(SFAS 133).
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a portion of
its future oil and gas production. These strategies include:
(i) For swap instruments, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due
to or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" limiting the
counterparty's exposure. In other words, there is no limit to
Chesapeake's exposure but there is a limit to the downside
exposure of the counterparty.
(iii) Basis protection swaps are arrangements that guarantee a price
differential of oil or gas from a specified delivery point.
Chesapeake receives a payment from the counterparty if the price
differential is greater than the stated terms of the contract and
pays the counterparty if the price differential is less than the
stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's hedging
activity is dynamic. As market conditions warrant, the company may elect to
settle a hedging transaction prior to its scheduled maturity date and, 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. Open
NYMEX NYMEX Swap
Strike Gain Price Positions
Price (Loss) Including Assuming as a % of
Open Of from Open & Gas Estimated
Swaps Open 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(A) 188.3 $6.46 -$0.22 $6.24 395.0 48%
Total 2006(A) 39.3 $6.77 -$0.62 $6.15 443.0 9%
Total 2007(B) --- --- --- --- 470.0 ---
TOTALS
2005-2007 227.6 $6.51 -$0.29 $6.22 1,308.0 17%
(A) 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.
(B) 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.
The company has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Production
Volume in Bcf's NYMEX less: in Bcf's of: % Hedged
2005 188.6 0.26 392.0 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 Swap
Assuming Oil Positions as % of
Open Swaps Avg. NYMEX Production Total Estimated
in mbo's Strike Price in mbo's of: 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(A) 2,271.0 $41.02 6,600 34%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $26.00 to $34.00 covering 1,996 mbo in 2005.
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 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-$1,400 $1,450-$1,550
mm mm mm mm
(A) Does not include gains or losses on interest rate derivatives
(SFAS 133).
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a portion of
its future oil and gas production. These strategies include:
(i) For swap instruments, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due
to or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" limiting the
counterparty's exposure. In other words, there is no limit to
Chesapeake's exposure but there is a limit to the downside
exposure of the counterparty.
(iii) Basis protection swaps are arrangements that guarantee a price
differential of oil or gas from a specified delivery point.
Chesapeake receives a payment from the counterparty if the price
differential is greater than the stated terms of the contract and
pays the counterparty if the price differential is less than the
stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's hedging
activity is dynamic. As market conditions warrant, the company may elect to
settle a hedging transaction prior to its scheduled maturity date and, 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 Gain Price Positions
Strike (Loss) Including Assuming as a % of
Open Price from Open & 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 62.2 $5.15 $0.00 $5.15 76.5 81%
3rd Qtr(A) 70.7 $5.49 -$0.09 $5.40 83.2 85%
4th Qtr(A) 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(A) 158.9 $6.41 -$0.24 $6.17 394.7 40%
Total
2006(A) 39.3 $6.77 -$0.62 $6.15 443.0 9%
Total
2007(B) --- --- --- --- 470.0 ---
TOTALS
2005-2007 198.2 $6.48 -$0.31 $6.17 1,307.7 15%
(A) 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.
(B) 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.
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 0.17 318.8 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
Avg. Open Swap
NYMEX Assuming Oil Positions as %
Open Swaps Strike Production of Total
in mbo's Price in mbo's of: Estimated Production
Q1 - 2004 1,270 $28.58 1,465 87%
Q2 - 2004 1,540 $30.00 1,673 92%
Q3 - 2004(A) 1,519 $30.32 1,834 83%
Q4 - 2004(A) 1,518 $30.10 1,588 96%
Total 2004(A) 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(A) 1,996 $40.20 6,600 30%
(A) 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.
SOURCE Chesapeake Energy Corporation
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Related links:
http://www.chkenergy.com
CONTACT:
Marc Rowland, Executive Vice President and
Chief Financial Officer, +1-405-879-9232, or Tom Price, Jr.,
Senior Vice President-Investor Relations, +1-405-879-9257, both
of Chesapeake Energy Corporation
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