EXHIBIT 99.1
------------
CHESAPEAKE ENERGY CORPORATION ANNOUNCES ACQUISITION
OF BARNETT SHALE NATURAL GAS PROPERTY FROM
HALLWOOD ENERGY CORPORATION FOR $277 MILLION
COMPANY TO ACQUIRE 18,000 ACRE NORTH BLOCK PROPERTY IN JOHNSON COUNTY,
TEXAS, LOCATED JUST NORTH OF CHESAPEAKE'S EXISTING 44%-OWNED
30,000 ACRE SOUTH BLOCK JOINT VENTURE WITH HALLWOOD
TRANSACTION INCLUDES PRODUCTION OF 25 MMCFE PER DAY AND 280 BCFE
OF INTERNALLY ESTIMATED RESERVES, CONSISTING OF 135 BCFE OF PROVED
RESERVES AND 145 BCFE OF PROBABLE AND POSSIBLE RESERVES
ACQUISITION BOOSTS CHESAPEAKE'S PRODUCTION FORECAST BY 3.6% FOR 2005 AND
5.8% FOR 2006 AS ESTIMATED PRODUCTION ON ACQUIRED PROPERTY INCREASES
TO 40 MMCFE PER DAY IN 2005 AND 70 MMCFE PER DAY IN 2006
OKLAHOMA CITY, OKLAHOMA, NOVEMBER 30, 2004 - Chesapeake today announced that it
has entered into an agreement with Hallwood Energy Corporation to acquire
Hallwood's 18,000 acre North Block property in Johnson County, Texas for $277
million in cash. This property is located immediately north of Hallwood's 30,000
acre South Block property, in which Chesapeake acquired a 44% working interest
through its June 2002 acquisition of Canaan Energy Corporation.
In this transaction, Chesapeake anticipates acquiring an internally estimated
135 billion cubic feet of natural gas equivalent proved reserves (bcfe), 145
bcfe of probable and possible reserves and net production of approximately 25
million cubic feet of natural gas equivalent production (mmcfe) per day from 31
vertical wells and 11 horizontal wells. Chesapeake has identified approximately
70 proved undeveloped and 90 probable and possible horizontal drilling locations
on the 18,000 acre North Block that it believes can be drilled at an average
cost of approximately $2.2 million per well to develop estimated ultimate
reserves (EUR) of 2.5 bcfe per well. Pro forma for this acquisition,
Chesapeake's proved oil and natural gas reserves will increase to an internally
estimated 4.6 trillion cubic feet of natural gas equivalent (tcfe) as of
September 30, 2004.
After allocating $98 million of the $277 million purchase price to undeveloped
leasehold, Chesapeake's acquisition cost for the 135 bcfe of internally
estimated proved reserves will be $1.33 per thousand cubic feet of natural gas
equivalent (mcfe). Including $303 million of anticipated future drilling costs
to fully develop the proved, probable and possible (3P) reserves, the company
estimates that its all-in acquisition cost for the 280 bcfe of 3P reserves will
be $2.07 per mcfe. In addition, Chesapeake has agreed to purchase Hallwood's
North Block gas gathering, compression and water disposal assets for $15
million.
The North Block proved reserves have a reserves-to-production index of 14.8
years, are 100% gas, are 15% proved developed, have current lease operating
expenses of $0.22 per mcfe, have severance taxes of 1.3% of the wellhead revenue
value and will be 100% Chesapeake-operated. The property's very low lease
operating expenses (approximately $0.53 per mcfe below the industry average) and
unusually low severance taxes (approximately $0.37 below the standard 7.5% Texas
severance tax rate at $6.00 per mcf because of severance tax reductions
applicable to certain types of newly drilled wells in Texas) create an
approximate $0.90 per mcfe economic advantage over typical Mid-Continent natural
gas properties.
Through the use of a three-rig drilling program, the company believes it can
increase gas production on the acquired property from 25 mmcfe per day in
December 2004 to at least 55 mmcfe per day by December 2005 and to at least 85
mmcfe per day by December 2006. If these production increases are achieved,
Chesapeake estimates that its average daily production in 2005 and 2006 will
increase by 40 and 70 mmcfe per day, respectively (see Chesapeake's updated
Outlook as of November 30, 2004 attached as Exhibit "A"). The company has hedged
the current 25 mmcfe per day of acquired production at NYMEX gas prices of $7.15
per mmbtu and $6.63 per mmbtu for 2005 and 2006, respectively, well above the
gas prices used to evaluate the property.
The acquisition is expected to close on December 15, 2004 and is subject to
customary closing conditions. The company intends to finance the acquisition
using a portion of the proceeds from a new $600 million private issue of senior
notes.
Hallwood is a private company and was advised in the sale by Albrecht &
Associates, Inc. of Houston, Texas.
MANAGEMENT COMMENT
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are
pleased to announce today's acquisition of the Hallwood North Block acreage for
several reasons. First, we are building our Barnett Shale ownership and creating
economies of scale by leveraging off our acquisition of Canaan Energy
Corporation in June 2002. In that $120 million transaction we inherited an
initial Barnett Shale leasehold position in Johnson County, Texas, to which we
initially gave no value. Today it appears that Chesapeake's South Block Barnett
Shale position may be worth more than what we paid for the entire Canaan
transaction.
Second, Chesapeake is well positioned to continue Hallwood's successful
production ramp-up currently underway, having worked closely with Hallwood for
two years in the South Block and because of our extensive experience with
horizontal drilling (more than 285 horizontal wells drilled in Texas since 1990)
and 3-D seismic (more than 9.0 million acres owned). Hallwood's use of
horizontal drilling, innovative completion techniques and 3-D seismic
information during the past few years has been very effective on both the 18,000
North Block property and the 30,000 acre South Block property.
Finally, we believe we have been conservative in our reserve estimates for the
acquired property, both with regard to our estimated EUR's of 2.5 bcfe per
horizontal well and to our planned PUD drilling pattern of 140 acres and 2,000'
standoffs for horizontal wellbores. Over time, we are hopeful that our reserve
estimates can increase and that our well spacing can decrease, leading to
significantly higher recoverable proved reserves than currently projected. We
look forward to adding further value to this prolific gas-producing area of the
Mid-Continent region in the years to come."
CONFERENCE CALL INFORMATION
A conference call has been scheduled for Wednesday morning, December 1, 2004 at
9:00 a.m. EST to discuss this release. The telephone number to access the
conference call is 913.981.5592. For those unable to participate in the
conference call, a replay will be available from 12:00 p.m. EST, December 1,
2004 through midnight EST on December 14, 2004. The number to access the
conference call replay is 719.457.0820 and the passcode is 915998. 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.
2
THIS PRESS RELEASE AND THE ACCOMPANYING OUTLOOKS INCLUDE "FORWARD-LOOKING
STATEMENTS" WITHIN THE MEANING OF SECTION 27A OF THE SECURITIES ACT OF 1933 AND
SECTION 21E OF THE SECURITIES EXCHANGE ACT OF 1934. FORWARD-LOOKING STATEMENTS
GIVE OUR CURRENT EXPECTATIONS OR FORECASTS OF FUTURE EVENTS. THEY INCLUDE
ESTIMATES OF OIL AND GAS RESERVES, EXPECTED OIL AND GAS PRODUCTION AND FUTURE
EXPENSES, PROJECTIONS OF FUTURE OIL AND GAS PRICES, PLANNED CAPITAL EXPENDITURES
FOR DRILLING, LEASEHOLD ACQUISITIONS AND SEISMIC DATA, AND STATEMENTS CONCERNING
ANTICIPATED CASH FLOW AND LIQUIDITY, BUSINESS STRATEGY AND OTHER PLANS AND
OBJECTIVES FOR FUTURE OPERATIONS. DISCLOSURES CONCERNING DERIVATIVE CONTRACTS
AND THEIR ESTIMATED CONTRIBUTION TO OUR FUTURE RESULTS OF OPERATIONS ARE BASED
UPON MARKET INFORMATION AS OF A SPECIFIC DATE. THESE MARKET PRICES ARE SUBJECT
TO SIGNIFICANT VOLATILITY.
FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM EXPECTED
RESULTS ARE DESCRIBED UNDER "RISK FACTORS" IN OUR PROSPECTUS DATED SEPTEMBER 10,
2004 FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON SEPTEMBER 10, 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. ALSO, OUR INTERNAL ESTIMATES OF RESERVES, PARTICULARLY
THOSE IN THE PROPERTY PROPOSED TO BE ACQUIRED WHERE WE MAY HAVE LIMITED REVIEW
OF DATA OR EXPERIENCE WITH THE RESERVES, MAY BE SUBJECT TO REVISION AND MAY BE
DIFFERENT FROM ESTIMATES BY OUR EXTERNAL RESERVOIR ENGINEERS AT YEAR-END.
ALTHOUGH WE BELIEVE THE EXPECTATIONS, ESTIMATES 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 AND DATA OR BY KNOWN OR UNKNOWN RISKS AND UNCERTAINTIES.
THE SEC HAS GENERALLY PERMITTED OIL AND GAS COMPANIES, IN FILINGS MADE WITH THE
SEC, TO DISCLOSE ONLY PROVED RESERVES THAT A COMPANY HAS DEMONSTRATED BY ACTUAL
PRODUCTION OR CONCLUSIVE FORMATION TESTS TO BE ECONOMICALLY AND LEGALLY
PRODUCIBLE UNDER EXISTING ECONOMIC AND OPERATING CONDITIONS. WE USE THE TERMS
"PROBABLE" AND "POSSIBLE" RESERVES OR OTHER DESCRIPTIONS OF VOLUMES OF RESERVES
POTENTIALLY RECOVERABLE THROUGH ADDITIONAL DRILLING OR RECOVERY TECHNIQUES THAT
THE SEC'S GUIDELINES MAY PROHIBIT US FROM INCLUDING IN FILINGS WITH THE SEC.
THESE ESTIMATES ARE BY THEIR NATURE MORE SPECULATIVE THAN ESTIMATES OF PROVED
RESERVES AND ACCORDINGLY ARE SUBJECT TO SUBSTANTIALLY GREATER RISK OF BEING
ACTUALLY REALIZED BY THE COMPANY.
THE ANNOUNCEMENT OF A PROPOSED DEBT FINANCING IN THIS PRESS RELEASE SHALL NOT
CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITIES.
THE DEBT SECURITIES WILL LIKELY NOT BE REGISTERED UNDER THE SECURITIES ACT OF
1933 OR ANY STATE SECURITIES LAWS, AND MAY NOT BE OFFERED OR SOLD IN THE UNITED
STATES ABSENT REGISTRATION OR AN APPLICABLE EXEMPTION FROM THE REGISTRATION
REQUIREMENTS OF THE SECURITIES ACT AND STATE LAWS.
CHESAPEAKE ENERGY CORPORATION IS THE SIXTH 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.
3
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF NOVEMBER 30, 2004
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 November 30,
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.
The primary changes from our November 1, 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 40 mmcfe per day in 2005 and 70 mmcfe
per day in 2006 as a result of the announced acquisition of Hallwood Energy
Corporation. This increases our full-year 2005 production forecast by 3.6%
to a mid-point of 1,155 mmcfe per day and our 2006 production forecast by
5.8% to a mid-point of 1,270 mmcfe per day.
2) We have increased capital expenditures by $50 million in each of 2005 and
2006 to reflect increased drilling activity planned on the Hallwood North
Block property.
3) We have updated the projected effects from changes in our hedging positions
since our November 1, 2004 Outlook.
4) We have included our expectations for future NYMEX oil and gas prices to
illustrate hedging effects only.
5) We have adjusted equivalent shares outstanding to reflect i) the conversion
of our 6.75% preferred stock into common shares on November 22, 2004, ii) a
recent private exchange of 600,000 shares of our 6.0% preferred stock for
3.225 million of our common shares, and iii) our pending tender offer to
exchange our remaining 6.0% preferred stock for an estimated 21.2 million
common shares.
4
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 - 319 379 - 387 418 - 428
Gas Equivalent - Bcfe 98 - 99 356 - 358 418 - 426 458 - 468
1,069 975 1,155 1,270
DAILY GAS EQUIVALENT MIDPOINT - IN MMCFE
NYMEX PRICES (FOR CALCULATION OF REALIZED
HEDGING EFFECTS ONLY):
Oil - $/Bo $46.67 $41.00 $40.00 $36.00
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):
-$15.85 -$10.19 $0.06 $0.00
OIL - $/BO
-$0.53 -$0.23 $0.05 -$0.01
GAS - $/MCF
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 $1.65 - 1.75 $1.75 - 1.85
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 - $1,250 - $1,350 -
mm $1,150 mm $1,350 mm $1,450 mm
(a) Does not include gains or losses on interest rate derivatives (SFAS 133).
5
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.
6
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 60.6 $6.89 -$0.11 $6.78 91.5 66%
2nd Qtr 34.9 $5.97 -$0.30 $5.67 94.5 37%
3rd Qtr 30.8 $5.96 -$0.35 $5.61 97.5 32%
4th Qtr 21.6 $6.10 -$0.50 $5.60 99.5 22%
Total 2005(1) 147.9 $6.36 -$0.26 $6.10 383.0 39%
===========================================================================================
===========================================================================================
Total 2006(1)(2) 32.0 $6.62 -$0.76 $5.86 423.0 8%
===========================================================================================
===========================================================================================
Total 2007(2) - - - - 450.0 -
===========================================================================================
- -------------------------------------------------------------------------------------------
TOTALS
- -------------------------------------------------------------------------------------------
2005-2007 179.9 $6.41 -$0.35 $6.06 1,256.0 14%
- -------------------------------------------------------------------------------------------
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $3.50 to $5.25 covering 25.4 bcf in 2004, $3.75 to $5.00
covering 52.9 bcf in 2005 and $3.75 to $5.25 covering 21.1 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.
(3) Not shown above are collard 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.
7
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 186.1 0.26 383.0 49%
2006 124.1 0.31 423.0 29%
2007 118.7 0.27 450.0 26%
2008 108.0 0.25 475.0 23%
2009 80.3 0.28 500.0 16%
----------------- ---------------- ------------------ ------
Totals 774.6 $ 0.25 2,549.8 30%
================= ================ ================== ======
* 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 Priee 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 Heding arrangements include swaps with knockout prices randing from
$21.00 TO $26.00 covering 2,240 mno in 2004 and knockout proces ranging
from $26.00 TO $34.00 covering 1,996 mbo in 2005.
8
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF NOVEMBER 1, 2004
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF NOVEMBER 30, 2004
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 November 1,
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.
The primary changes from our July 26, 2004 Outlook are in italicized bold in the
table and are explained as follows:
1) We have deleted our 2004 third quarter forecast and have updated our
forecasts for the 2004 fourth quarter, the full-year 2004 and full-year
2005 forecasts and have provided our initial 2006 forecast.
2) We have updated our previous production forecast for the full-year 2004
to reflect actual third quarter 2004 production, which exceeded the
mid-point of our guidance by 24 mmcfe per day, or 2.4%. In addition, we
have revised upward our fourth quarter 2004 production forecast by 20
mmcfe per day, or 2.0%, from the mid-point of our previous guidance,
ii) our full-year 2004 production forecast by 8 mmcfe per day, or 0.8%,
from the mid-point of our previous guidance, iii) our full-year 2005
forecast by 33 mmcfe per day, or 3.0%, from the mid-point of our
previous guidance, all to account for better than expected 2004
drilling results. The mid-point of our initial 2006 production forecast
is 438 bcfe, or 1,200 mmcfe per day, a projected increase of 7.6% over
the midpoint of our revised 2005 forecast and 23.1% above the mid-point
of our revised 2004 production forecast.
3) We have updated the projected effects from changes in our hedging
positions since our July 26, 2004 Outlook.
4) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only.
5) For ease of reconciliation, please note that our first quarter 2004
production was 78.9 bcfe, our second quarter 2004 production was 86.5
bcfe, our third quarter production was 94.2 bcfe and our first nine
months 2004 production was 259.7 bcfe. Our July 26, 2004 Outlook
forecasted a third quarter 2004 production range of 91.5 to 92.5 bcfe
and a full-year 2004 production range of 353 to 355 bcfe. The
differences are attributable to better than expected 2004 drilling
results.
9
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 - 319 364 - 372 393 - 403
Gas Equivalent - Bcfe 98 - 99 356 - 358 403 - 411 433 - 443
1,069 975 1,115 1,200
DAILY GAS EQUIVALENT MIDPOINT - IN MMCFE
NYMEX PRICES (FOR CALCULATION OF REALIZED
HEDGING EFFECTS ONLY):
Oil - $/Bo $46.67 $41.00 $40.00 $36.00
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):
-$15.85 -$10.19 $0.06 $0.00
OIL - $/BO
-$0.53 -$0.23 $0.00 -$0.04
GAS - $/MCF
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 $1.65 - 1.75 $1.75 - 1.85
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
36% 36% 36% 36%
Book Tax Rate
Equivalent Shares Outstanding:
Basic 279 mm 254 mm 288 mm 290 mm
Diluted 347 mm 317 mm 349 mm 352 mm
Capital Expenditures:
Drilling, leasehold and seismic $300 - $325 $1,100 - $1,200 - $1,300 -
mm $1,150 mm $1,300 mm $1,400 mm
(a) Does not include gains or losses on interest rate derivatives (SFAS 133).
10
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.
11
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 56.1 $6.82 -$0.17 $6.65 92.0 61%
2nd Qtr 30.4 $5.86 -$0.35 $5.51 92.0 33%
3rd Qtr 26.2 $5.77 -$0.41 $5.36 92.0 28%
4th Qtr 17.0 $5.85 -$0.63 $5.22 92.0 18%
====================================================================================================================
Total 2005(1) 129.7 $6.26 -$0.30 $5.96 368.0 35%
====================================================================================================================
====================================================================================================================
Total 2006(1)(2) 13.8 $6.64 -$1.77 $4.87 398.0 3%
====================================================================================================================
====================================================================================================================
Total 2007(2) - - - - 430.0 -
- --------------------------------------------------------------------------------------------------------------------
====================================================================================================================
TOTALS
- --------------------------------------------------------------------------------------------------------------------
2005-2007 143.5 $6.30 -$0.44 $5.86 1,196.0 12%
====================================================================================================================
(1) Certain hedging arrangmentsS include swaps with knockout prcesS ranging
from $3.50 to $5.25 covering 25.4 bcf in 2004, $3.75 TO $5.00 covering 52.9
bcf in 2005 and $3.75 TO $5.25 covering 21.1 bcf in 2006.
(2) Swaps covering 25.6 bcf have been locked for 2007. This will result in the
recognitiion of $11.6 million of ;osses in 2007 when the hedging
arrangements settle.
(3) 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.
12
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 175.2 0.25 368.0 48%
2006 113.1 0.30 398.0 28%
2007 107.7 0.26 430.0 25%
2008 108.0 0.25 460.0 23%
2009 80.3 0.28 490.0 16%
----------------- ---------------- ------------------ ------
Totals 741.7 $ 0.26 2,464.8 30%
================= ================ ================== ======
* 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 Priee 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%
------------------------------------------------------------------------------------------------
5,847 $29.80 6,560 89%
Total 2004(1)
================================================================================================
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 mco in 2005.
13