EXHIBIT 99.1
------------
CHESAPEAKE ENERGY CORPORATION ANNOUNCES
PROPOSED ACQUISITION OF MID-CONTINENT AND ARK-LA-TEX NATURAL
GAS PROPERTIES FROM BRG PETROLEUM CORPORATION
FOR $325 MILLION
Transaction Will Include Production of 30 Mmcfe Per Day and 500 Bcfe
of Internally Estimated Reserves, Consisting of 223 Bcfe of Proved
Reserves and 277 Bcfe of Probable and Possible Reserves
Acquisition Will Boost Chesapeake's Production Forecast by 2.8% for 2005
and 4.3% for 2006 as Estimated Average Daily Production Should Increase
by 35 Mmcfe Per Day in 2005 and 55 Mmcfe Per Day in 2006
OKLAHOMA CITY, OKLAHOMA, DECEMBER 27, 2004 - Chesapeake Energy Corporation
(CHK:NYSE) today announced that it has entered into an agreement to acquire
Tulsa-based privately-held BRG Petroleum Corporation and related partnerships
for $325 million in cash. In this transaction, Chesapeake anticipates acquiring
an internally estimated 223 billion cubic feet of natural gas equivalent proved
reserves (bcfe), 277 bcfe of probable and possible reserves and net production
of approximately 30 million cubic feet of natural gas equivalent production
(mmcfe) per day from 477 existing wells.
After allocating $71 million of the $325 million purchase price to BRG's
estimated 120,000 net acres of undeveloped leasehold (and related probable and
possible reserves) and $5 million to mid-stream assets, Chesapeake's acquisition
cost for the 223 bcfe of internally estimated proved reserves will be $1.12 per
thousand cubic feet of natural gas equivalent (mcfe). Including $492 million of
anticipated future costs to fully develop the proved, probable and possible (3P)
reserves, the company estimates that its all-in acquisition cost for acquiring
and developing the 500 bcfe of 3P reserves should be $1.62 per mcfe based on the
company's projected development plan and anticipated future drilling costs. The
BRG proved reserves have a reserves-to-production index of 20.3 years (9.7 years
excluding proved undeveloped reserves), are 93% gas, are 48% proved developed,
have current lease operating expenses of $0.53 per mcfe and will be 96%
Chesapeake-operated (by value).
BRG's properties are concentrated in the Mid-Continent and Ark-La-Tex regions.
In these areas, Chesapeake has identified 213 proved undeveloped and 420
probable and possible locations on BRG's leasehold. The drilling locations are
concentrated in the Sahara gas resource play in Northwest Oklahoma and in the
East Texas Cotton Valley gas resource play in Nacogdoches County, Texas. Current
well economics in Sahara involve investing $550,000 to develop an estimated
ultimate recovery (EUR) of 0.6 bcfe and current Cotton Valley economics in
Nacogdoches County involve investing $900,000 to develop an estimated EUR of 0.9
bcfe. Pro forma for this acquisition, Chesapeake expects that its proved oil and
natural gas reserves will increase to an internally estimated 4.8 trillion cubic
feet of natural gas equivalent (tcfe) as of December 31, 2004.
Through the use of two rigs in 2005 and four rigs in 2006, the company believes
it can increase gas production on the acquired properties from 30 mmcfe per day
at closing in February 2005 to 40 mmcfe per day in December 2005 and to 70 mmcfe
per day in December 2006. If these production increases are achieved, Chesapeake
estimates that its total average daily production in 2005 and 2006 will increase
by 35 and 55 mmcfe per day, respectively (see Chesapeake's updated Outlook as of
December 27, 2004 attached as Exhibit "A"). The company has hedged 67% of BRG's
current gas production at NYMEX gas prices of $7.42 per mmbtu and $7.45 per
mmbtu for 2005 and 2006, respectively, well above the gas prices used to
evaluate the property.
The BRG acquisition is expected to close on February 1, 2005 and is subject to
customary closing conditions and purchase price adjustments. The company intends
to finance the acquisition from cash on hand and by using its bank credit
facility. Chesapeake expects to expand its bank credit facility to $1 billion
and to extend the maturity of the facility to 2010. BRG was advised in the sale
by Randall & Dewey of Houston, Texas.
MANAGEMENT COMMENT
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are
pleased to announce today's proposed acquisition of BRG for several reasons.
First, BRG will add to our very strong presence in the Mid-Continent, especially
in the Sahara region of Northwest Oklahoma. Since establishing our initial
Sahara position by acquiring 50,000 net leasehold acres through our acquisitions
of DLB Oil & Gas, Inc. and Hugoton Energy Corporation in 1998, we now control
more than 500,000 net acres in Sahara. To date, we have drilled more than 600
wells in this area and believe we can drill approximately 2,500 additional wells
in the next 5-10 years, providing more than 1 tcfe of potential gas resource
upside to Chesapeake's existing approximate five tcfe of proved reserves. We
believe Sahara is one of the great gas resources plays in the U.S. and
fortunately from a competitive standpoint, one of the least recognized by the
industry.
In addition, through BRG we will be building on Chesapeake's Ark-La-Tex position
that was initially established through our Greystone Petroleum LLC transaction
in June 2004. In that transaction, we acquired a significant interest in the
Sligo Field in North Louisiana's Bossier Parish. In just seven months, we have
increased our net production on the property from 45 mmcfe per day to today's
rate of approximately 60 mmcfe per day. In addition, from an estimated proved
reserve base of 214 bcfe at the date of acquisition, we have already been able
to increase Greystone's proved reserves by approximately 10%.
In this latest Ark-La-Tex acquisition, Chesapeake will be acquiring 42,000 gross
(37,000 net) leasehold acres in the Naconiche Creek area of Nacogdoches County,
Texas from BRG. During the past few years, BRG has drilled more than 75 wells in
this area to prove the commerciality of this promising gas resource play. We now
intend to accelerate further development of the field by drilling over 600
additional wells that should develop an average estimated EUR of 0.9 bcfe per
well for a per well investment of $900,000. After royalties, our finding costs
should be approximately $1.25 per mcfe with virtually no dry-hole risk.
In the BRG transaction, as with all of our acquisitions, we are hopeful that
over time our reserve estimates will increase and that our well spacing will
decrease, leading to significantly higher recoverable reserves than originally
projected at the time of acquisition. We look forward to adding further value to
the attractive gas resource plays acquired from BRG in the years to come."
HALLWOOD TRANSACTION CLOSES AS SCHEDULED
On December 15, 2004, Chesapeake closed its $292 million acquisition of Barnett
Shale properties from Dallas-based Hallwood Energy Corporation. In the Hallwood
acquisition, Chesapeake acquired Hallwood's 18,000 acre North Block assets in
Johnson County, Texas. Through this transaction, Chesapeake acquired 135 bcfe of
proved reserves, 145 bcfe of probable and possible reserves and net production
of approximately 25 mcfe per day. Chesapeake is currently utilizing two rigs to
further develop the North Block assets and is participating as non-operator in
two rigs operated by Hallwood that are operating on Hallwood's South Block, in
which Chesapeake owns a 44% working interest.
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 EXCHANGE OFFER PROSPECTUS
DATED NOVEMBER 30, 2004 (AS AMENDED ON DECEMBER 16, 2004) WE 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 UNDERTAKING
AND OUTCOME OF FUTURE DRILLING ACTIVITY, WHICH MAY BE AFFECTED BY SIGNIFICANT
COMMODITY PRICE DECLINES OR DRILLING COST INCREASES. ALSO, OUR INTERNAL
ESTIMATES OF RESERVES, PARTICULARLY THOSE IN THE PROPERTIES 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 OR ULTIMATELY 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 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 DECEMBER 27, 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 December 27,
2004, we are using the following key assumptions in our projections for the
fourth quarter of 2004, the full-year 2004, the full-year 2005 and the full-year
2006.
We expect to record non-operating losses in Q4 2004 in connection with our
pending cash tender offer for our $209.8 million of 8.375% senior notes due 2008
and our pending offer to exchange our 6.0% convertible preferred stock for our
common stock. If we purchase all of our 8.375% senior notes pursuant to the
tender offer, we estimate that an after-tax loss on the early redemption of the
notes of $12 million will be recorded in Q4 2004 as an adjustment to net
earnings. If all our 6.0% preferred stock is exchanged for common stock, we
estimate that a loss on the early conversion of the preferred stock of
approximately $37 million will be reflected as an adjustment to net income
available to common shareholders for the purpose of calculating basic earnings
per share in Q4 2004.
The primary changes from our November 30, 2004 Outlook are in italicized bold in
the table and are explained as follows:
1) We have updated our previous production forecasts for 2005 and 2006 to
reflect increases in production of 35 mmcfe per day in 2005 (excluding
January) and 55 mmcfe per day in 2006 as a result of the announced
acquisition of BRG Petroleum Corporation. This increases our full-year
2005 production forecast by 2.8% to a mid-point of 1,190 mmcfe per day
and our 2006 production forecast by 4.3% to a mid-point of 1,325 mmcfe
per day.
2) We have increased capital expenditures by $50 million in 2005 and $100
million in 2006 to reflect planned increased drilling activity planned
on the BRG and other company properties.
3) We have updated the projected effects from changes in our hedging
positions since our November 30, 2004 Outlook.
4) We have included our expectations for future NYMEX oil and gas prices
to illustrate hedging effects only.
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 - 319 391 - 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 mm $1,100 - $1,150 $1,300 - $1,450 - $1,550
mm $1,400 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.
5
Commodity markets are volatile, and as a result, Chesapeake's hedging
activity is dynamic. As market conditions warrant, the company may
elect to settle a hedging transaction prior to its scheduled maturity
date and, as a result, lock in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions in
order to mitigate a portion of its exposure to adverse market changes
in oil and natural gas prices. Accordingly, associated gains or loses
from the derivative transactions are reflected as adjustments to oil
and gas sales. All realized gains and losses from oil and natural gas
derivatives are included in oil and gas sales in the month of related
production. Pursuant to SFAS 133, certain derivatives do not qualify
for designation as cash flow hedges. Changes in the fair value of
these non-qualifying derivatives that occur prior to their maturity
(i.e. because of temporary fluctuations in value) are reported
currently in the consolidated statement of operations as unrealized
gains (losses) within oil and gas sales.
Following provisions of SFAS 133, changes in the fair value of
derivative instruments designated as cash flow hedges, to the extent
effective in offsetting cash flows attributable to hedged risk, are
recorded in other comprehensive income until the hedged item is
recognized in earnings. Any change in fair value resulting from
ineffectiveness is recognized currently in oil and natural gas sales.
The company currently has in place the following natural gas swaps:
% Hedged
---------------------------
Avg. Avg. NYMEX Open Swap
NYMEX Price Positions as
Strike Including Assuming a % of
Open Price Gain (Loss) Open and Gas Estimated
Swaps of Open from Locked Locked Production Total Gas
in Bcf's Swaps Swaps Positions in Bcf's of: Production
--------- ------- ---------- ----------- ------------- -----------
2004:
- -----
1st Qtr 69.5 $5.94 $0.03 $5.97 70.1 99%
2nd Qtr 62.2 $5.15 $0.00 $5.15 76.5 81%
3rd Qtr(1) 70.7 $5.49 -$0.09 $5.40 83.2 85%
4th Qtr(1) 76.5 $5.88 -$0.11 $5.77 89.0 86%
- --------------------------------------------------------------------------------------------
Total 2004 278.9 $5.63 -$0.05 $5.58 318.8 88%
============================================================================================
============================================================================================
2005:
- -----
1st Qtr 62.4 $6.91 -$0.11 $6.80 93.4 67%
2nd Qtr 38.5 $6.05 -$0.27 $5.78 97.5 39%
3rd Qtr 34.5 $6.06 -$0.31 $5.75 100.8 34%
4th Qtr 23.5 $6.20 -$0.46 $5.74 103.0 23%
============================================================================================
Total 2005(1) 158.9 $6.41 -$0.24 $6.17 394.7 40%
============================================================================================
============================================================================================
Total 2006(1) 39.3 $6.77 -$0.62 $6.15 443.0 9%
============================================================================================
============================================================================================
Total 2007(2) - - - - 470.0 -
============================================================================================
============================================================================================
TOTALS
- --------------------------------------------------------------------------------------------
2005-2007 198.2 $6.48 -$0.31 $6.17 1,307.7 15%
============================================================================================
(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 $5.50
COVERING 60.2 BCF IN 2005 AND $3.75 TO $5.50 COVERING 28.4 BCF IN
2006.
(2) SWAPS COVERING 25.6 BCF HAVE BEEN LOCKED FOR 2007. THIS WILL RESULT IN
THE RECOGNITION OF $11.6 MILLION OF LOSSES IN 2007 WHEN THE HEDGING
ARRANGEMENTS SETTLE.
NOTE: NOT SHOWN ABOVE ARE COLLARS COVERING 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.
6
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
---------------------------------
Assuming Open Swap
Avg. Oil Positions as
Open NYMEX Production % of Total
Swaps in Strike in mbo's Estimated
mbo's Price of: Production
-------- ------- ---------- ------------
Q1 - 2004 1,270 $28.58 1,465 87%
Q2 - 2004 1,540 $30.00 1,673 92%
Q3 - 2004(1) 1,519 $30.32 1,834 83%
Q4 - 2004(1) 1,518 $30.10 1,588 96%
- -------------------------------------------------------------------------------
Total 2004(1) 5,847 $29.80 6,560 89%
==============================================================
==============================================================
Q1 - 2005 855 $41.76 1,650 52%
Q2 - 2005 865 $41.63 1,650 52%
Q3 - 2005 138 $31.16 1,650 8%
Q4 - 2005 138 $30.62 1,650 8%
- -------------------------------------------------------------------------------
Total 2005(1) 1,996 $40.20 6,600 30%
==============================================================
(1) CERTAIN HEDGING ARRANGEMENTS INCLUDE SWAPS WITH KNOCKOUT PRICES
RANGING FROM $21.00 TO $26.00 COVERING 2,240 MBO IN 2004 AND KNOCKOUT
PRICES RANGING FROM $26.00 TO $34.00 COVERING 1,996 MBO IN 2005.
7
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF NOVEMBER 30, 2004
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF DECEMBER 27, 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.
8
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
Daily gas equivalent midpoint - in Mmcfe 1,069 975 1,155 1,270
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):
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 $1.65 - 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 mm $1,100 - $1,150 $1,250 - $1,350 $1,350 -
mm mm $1,450 mm
(a) Does not include gains or losses on interest rate derivatives (SFAS 133).
9
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.
10
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.
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.
11
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
---------------------------------
Assuming Open Swap
Avg. Oil Positions as
Open NYMEX Production % of Total
Swaps in Strike in mbo's Estimated
mbo's Price of: Production
-------- ------ ----------- ------------
Q1 - 2004 1,270 $28.58 1,465 87%
Q2 - 2004 1,540 $30.00 1,673 92%
Q3 - 2004(1) 1,519 $30.32 1,834 83%
Q4 - 2004(1) 1,518 $30.10 1,588 96%
- -------------------------------------------------------------------------------
Total 2004(1) 5,847 $29.80 6,560 89%
===============================================================
Q1 - 2005 855 $41.76 1,650 52%
Q2 - 2005 865 $41.63 1,650 52%
Q3 - 2005 138 $31.16 1,650 8%
Q4 - 2005 138 $30.62 1,650 8%
- --------------------------------------------------------------------------------
Total 2005(1) 1,996 $40.20 6,600 30%
===============================================================
(1) Certain hedging arrangements include swaps with knockout prices
ranging from $21.00 to $26.00 covering 2,240 mbo in 2004 and knockout
prices ranging from $26.00 to $34.00 covering 1,996 mbo in 2005.
12