Company Will Acquire Production of 125 Mmcfe Per Day and Internally Estimated
Reserves of 2.5 Tcfe, Consisting of 1.1 Tcfe of Proved Reserves and 1.4 Tcfe
of Probable and Possible Reserves
Columbia Is the Fourth Largest Natural Gas Producer in the Appalachian Basin
and Largest Leaseholder, Owning 4.1 Million Net Acres on Which Chesapeake Has
Identified 9,435 Drilling Locations
Pro Forma for the Transaction, Chesapeake's Projected December 2005 Production
Rate Increases to 1,460 Mmcfe Per Day, Proved Reserves Reach 7.1 Tcfe, Proved
and Unproved Reserves Reach 13.5 Tcfe and Leasehold Inventory Doubles to
8.2 Million Net Acres
OKLAHOMA CITY, Oct. 3 /PRNewswire-FirstCall/ -- Chesapeake Energy
Corporation (NYSE: CHK) today announced that it has entered into an agreement
to acquire Columbia Natural Resources, LLC and certain affiliated entities
(CNR) from Triana Energy Holdings LLC (Triana) for $2.2 billion in cash, the
assumption of an estimated $75 million working capital deficit and liabilities
related to CNR's prepaid sales agreement and hedging positions.
Through this transaction, Chesapeake anticipates acquiring an internally
estimated 2.5 trillion cubic feet of natural gas equivalent (tcfe) of proved,
probable and possible (3P) reserves, comprised of 1.1 tcfe of proved reserves
and 1.4 tcfe of probable and possible reserves. The seller's independent
third party engineering report calculated CNR's 3P reserves to be 3.9 tcfe, or
56% more 3P reserves than Chesapeake will initially recognize. CNR's current
daily net production is approximately 125 million cubic feet of natural gas
equivalent (mmcfe), indicating a proved reserves-to-production index of
23.0 years and a proved developed reserves-to-production index of 16.0 years.
The properties are principally located in West Virginia, Kentucky, Ohio,
Pennsylvania and New York.
After the preliminary allocation of $175 million of the $2.2 billion
purchase price (which excludes negative working capital and liabilities
associated with the assumed prepaid sales agreement and hedges) to CNR's
extensive mid-stream natural gas assets being acquired (including over 6,500
miles of natural gas gathering lines) and $500 million to the unevaluated
portion of the 4.1 million net leasehold acres being acquired (3.5 million net
acres in the U.S. and 0.6 million net acres in Canada), Chesapeake's
acquisition cost for the 1.1 tcfe of internally estimated proved reserves will
be approximately $1.45 per thousand cubic feet of natural gas equivalent
(mcfe). Based on the company's projected development plan, which includes
approximately $4.1 billion of anticipated future drilling and development
costs, Chesapeake estimates that its all-in cost of acquiring and developing
the 2.5 tcfe of 3P reserves will be approximately $2.48 per mcfe, exclusive of
the negative working capital and prepaid sales and hedging liabilities to be
assumed.
CNR's proved reserves are long-lived, have low production decline rates
(the proved developed producing base is projected to decline at less than 10%
per year), are 99% natural gas, have an average BTU content of 1,140 and are
70% proved developed. In addition, gas sold from the properties generally
receives a $0.50 per mmbtu premium to NYMEX gas prices, compared to basis
differential discounts that currently range up to $4.00 per mmbtu in various
southwestern and western U.S. natural gas supply basins. Adjusting further
for the favorable BTU content, CNR's natural gas today receives wellhead
prices of up to $5.00 per mcfe more than typical southwestern and western U.S.
natural gas production.
On the acquired properties, Chesapeake has identified 1,316 proved
undeveloped (PUD) locations, 6,286 probable locations and 1,833 possible
locations for a total of 9,435 undrilled locations, or an estimated drilling
inventory of more than 15 years. By comparison, the seller's independent
reservoir engineers identified 1,611 PUD locations (22% more than Chesapeake
will initially recognize) and over 14,000 probable and possible locations (72%
more than Chesapeake will initially recognize).
As of June 30, 2005 and pro forma for this acquisition, Chesapeake will
own an internally estimated 13.5 tcfe of proved and unproved oil and natural
gas reserves, comprised of 7.1 tcfe of proved reserves (which will be 92%
natural gas and 100% onshore) and 6.4 tcfe of unproved reserves. The company
intends to spend at least $200 million per year for the foreseeable future in
further developing the acquired properties and is budgeting production growth
from the acquired assets of 5-10% per year.
Chesapeake has begun the process of hedging the production it will acquire
from CNR. The company intends to hedge at least 50% of CNR's estimated base
production through December 2008. The prices received from such hedging
should significantly exceed the pricing assumptions used by Chesapeake to
value the properties.
As part of the transaction, the company will assume CNR's prepaid sales
agreement and its hedging arrangements. Chesapeake expects to record any
potential mark-to-market loss on those obligations as a balance sheet
liability when the transaction closes. The amount of the mark-to-market loss
will be dependent on gas prices on the day of closing. For example, using a
flat $7.00 NYMEX gas strip through December 2009, the prepaid sales and
hedging liabilities would be approximately $325 million. Using gas prices as
of September 30, 2005, the prepaid sales and hedging liabilities would be
approximately $775 million.
Chesapeake will soon file its Hart-Scott-Rodino (HSR) pre-merger
notification form with the Federal Trade Commission. Satisfaction of the HSR
requirements should occur within 30 days after filing. Accordingly, the
company anticipates closing the transaction no later than December 15, 2005.
The company intends to finance the acquisition from cash on hand and by
issuing a balanced combination of senior notes and equity securities. As a
result of this acquisition and the contemplated financings, the company has
attached its updated Outlook as Exhibit "A" to this release. The company's
previous Outlook, dated September 7, 2005, is attached as Exhibit "B" for
comparative purposes.
Triana was formed in 2001 by management and executives of Metalmark
Capital LLC as a Morgan Stanley Capital Partners portfolio company. Triana
was advised in this transaction by Morgan Stanley & Co. Incorporated and
Credit Suisse First Boston LLC.
Management Comment
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We
are excited to announce the acquisition of CNR for several reasons. First, we
will acquire very significant land and gas resource inventories to complement
our already very large land and gas resource inventories. CNR's additional
4.1 million net acres and 2.5 tcfe of 3P reserves will increase Chesapeake's
leasehold and gas resource inventories to 8.2 million net acres and 13.5 tcfe,
respectively. According to rankings published last week by the Oil & Gas
Journal, Chesapeake's pro forma 6.5 tcf of proved gas reserves will be the
third largest in the U.S., trailing only those of ExxonMobil and
ConocoPhillips. We believe this transaction will solidify Chesapeake's
position as the premier gas resource company in the industry.
"Secondly, we are very enthusiastic about moving into the large, prolific
and generally underexplored and unconsolidated Appalachian Basin. The basin
covers over 185,000 square miles (almost three times the size of Oklahoma)
across seven states and has produced more than 46 tcf of gas from over 400,000
wells. In 2003, the National Petroleum Council estimated the basin still
contained another 9 tcf of proved gas reserves and an additional 68 tcf of
unproved gas reserves. In addition, much of the basin remains underexplored.
Less than 1% of the 400,000 wells drilled to date have penetrated below 7,500
feet, leaving substantial deeper exploration opportunities available for
Chesapeake to pursue. We believe deep gas exploration is one of our most
important competitive strengths.
"Third, we are also attracted to the value proposition of producing
natural gas at a premium price to NYMEX, rather than for the steep discount to
NYMEX that most other U.S. natural gas sells for today. Some basis
differentials now exceed $4.00 per mmbtu, creating a very pronounced value
advantage for Appalachian Basin gas production. Including an approximate 14%
value upgrade for the rich BTU content of the gas, we believe prices realized
on CNR's gas production today would be more than $5.00 per mcfe higher than
prices received in most southwestern and western U.S. gas basins.
"In addition, we are eager to begin working in a large U.S. natural gas
basin that shares many similarities to our stronghold in the Mid-Continent,
where 59% of our pro forma production is located. As in the Mid-Continent
area seven years ago, Appalachian Basin asset ownership is very fragmented and
gas production has typically been developed by a large number of very small
private companies, a few mid-sized public independents and several large
pipeline and utility companies. We believe that Chesapeake's significant
presence in the Barnett, Woodford, Caney and Fayetteville shale plays, our
expertise in tight sand and horizontal coalbed methane drilling and our
commitment to deep natural gas exploration will enable us to achieve success
in Appalachia.
"Although the Appalachian Basin will be a new area for Chesapeake, we have
been in conversations with CNR's management for over three years and have been
educating ourselves about the basin during that time. We believe the
geological age of the reservoirs, the types of geological plays and the gas-
prospectivity of the basin are an excellent fit with Chesapeake's existing
competitive advantages. We look forward to decades of success in the
Appalachian Basin.
"And finally, it has become abundantly clear in the past month that the
U.S. needs significant additional supplies of clean-burning, domestically-
produced onshore natural gas. During the past five years, Chesapeake has been
the most active driller in the U.S. and has discovered and developed major new
supplies of natural gas that U.S. consumers increasingly need. In 2006, the
company plans to utilize an average of 85-90 drilling rigs to continue
exploring for new supplies of natural gas. While others in the industry are
increasingly focused on international projects, we remain committed to
supplying consumers with as much natural gas as Chesapeake can find onshore in
the U.S."
Henry Harmon, President and CEO of Triana said, "This transaction
underscores the success of combining Triana management's vision and the
longstanding partnership with executives of Metalmark Capital to create one of
the largest gas exploration and production companies in the Appalachian
Basin."
Conference Call Information
A conference call has been scheduled for Tuesday morning, October 4, 2005
at 9:00 a.m. EDT to discuss this press 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 noon EDT,
October 4, 2005 through midnight EDT on October 18, 2005. The number to
access the conference call replay is 719.457.0820 and the passcode is 5537544.
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 our expected acquisition of Columbia Natural Resources, LLC and
related financings, 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 the fair value of 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 item 1 of our 2004 Annual Report
on Form 10-K filed with the Securities and Exchange Commission on March 9,
2005. They include the volatility of oil and gas prices; adverse effects our
level of indebtedness could have on our operations and future growth; our
ability to compete effectively against strong independent oil and gas
companies and majors; the availability of capital on an economic basis to fund
reserve replacement costs; uncertainties inherent in estimating quantities of
oil and gas reserves and projecting future rates of production and the timing
of development expenditures; our ability to replace reserves and sustain
production; uncertainties in evaluating oil and gas reserves of acquired
properties and associated potential liabilities; unsuccessful exploration and
development drilling; declines in the values of our oil and gas properties
resulting in ceiling test write-downs; lower prices realized on oil and gas
sales and collateral required to secure hedging liabilities resulting from our
commodity price risk management activities; and drilling and operating risks.
In addition, the CNR acquisition is subject to conditions which must be
satisfied before closing. 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 properties recently acquired or 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 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", "possible" or "un-proven" to describe 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. While we believe our
calculations of unproven drillsites and estimation of unproven reserves have
been appropriately risked and are reasonable, such calculations and estimates
have not been reviewed by third party engineers or appraisers.
The announcement of proposed financings through the issuance of equity and
senior notes in this press release shall not constitute an offer to sell or a
solicitation of an offer to buy the securities. The terms of any such
offerings have not been decided. The securities may not be registered under
the Securities Act of 1933 or any state securities laws and, if not
registered, 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.
Pro forma for the CNR acquisition, Chesapeake Energy Corporation is the
second 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 property acquisitions in the Mid-Continent, Permian
Basin, South Texas, Texas Gulf Coast, Barnett Shale, Ark-La-Tex and, most
recently, the Appalachian Basin regions of the United States. The company's
Internet address is http://www.chkenergy.com .
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF OCTOBER 3, 2005
Quarter Ending September 30, 2005; Quarter Ending December 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 October
3, 2005, we are using the following key assumptions in our projections for the
third quarter of 2005, the fourth quarter of 2005, the full-year 2005 and the
full-year 2006.
The primary changes from our September 7, 2005 Outlook are in italicized
bold in the table and are explained as follows:
1) We have shown the operational and financial effects of the pending
acquisition and anticipated financing as described in our press
release dated October 3, 2005. We have assumed that the CNR
acquisition will close no later than December 15, 2005.
2) We have updated the projected effect of changes in our hedging
positions since our September 7, 2005 Outlook.
3) We have updated our expectations for future NYMEX oil and gas prices
based on current market conditions in order to illustrate hedging
effects only.
4) We have updated certain of our costs to reflect changing market
conditions and the impact of the CNR acquisition.
5) We have increased our estimated basic common share count to reflect
the common stock issued in connection with the exchanges of a portion
of our preferred stock during September 2005.
6) We have provided guidance for the fourth quarter of 2005.
Quarter Ending Quarter Ending Year Ending Year Ending
9/30/2005 12/31/2005 12/31/2005 12/31/2006
Estimated
Production:
Oil - Mbo 1,950 1,950 7,650 7,700
Gas - Bcf 107-109 112-114 416-419 512-522
Gas Equivalent
- Bcfe 118.5-120.5 124-126 462-465 558-568
Daily gas
equivalent
midpoint -
in Mmcfe 1,300 1,359 1,270 1,543
NYMEX Prices (for
calculation of
realized hedging
effects only):
Oil - $/Bo $61.34 $60.00 $56.09 $50.00
Gas - $/Mcf $8.53 $9.00 $7.64 $7.00
Estimated
Differentials to
NYMEX Prices:
Oil - $/Bo -$4.50 -$4.50 -$4.50 -$4.50
Gas - $/Mcf -$0.80 -$1.50 -$1.00 -$1.00
Estimated Realized
Hedging Effects
(based on expected
NYMEX prices above):
Oil - $/Bo -$4.48 -$2.78 -$4.09 $4.94
Gas - $/Mcf -$1.21 -$0.33 -$0.21 $0.66
Operating Costs per
Mcfe of Projected
Production:
Production
expense $0.68-0.72 $0.70-0.74 $0.68-0.72 $0.77-0.82
Production taxes
(generally 7%
of O&G
revenues) (A) $0.51-0.56 $0.56-0.60 $0.45-0.50 $0.45-0.50
General and
administrative $0.10-0.12 $0.10-0.12 $0.10-0.12 $0.11-0.13
Stock-based
compensation
(non-cash) $0.03-0.05 $0.03-0.05 $0.03-0.05 $0.04-0.06
DD&A - oil
and gas $1.85-1.95 $2.05-2.10 $1.85-1.95 $2.15-2.20
Depreciation of
other assets $0.09-0.11 $0.10-0.12 $0.09-0.11 $0.10-0.12
Interest
expense (B) $0.48-0.52 $0.48-0.52 $0.45-0.49 $0.48-0.53
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
(approximately
equal to 95%
deferred) 36.5% 36.5% 36.5% 36.5%
Equivalent Shares
Outstanding:
Basic 322 mm 342 mm 321 mm 355 mm
Diluted 376 mm 399 mm 373 mm 418 mm
Capital Expenditures:
Drilling,
leasehold
and seismic $485-$535 $575-$625 $2,000-$2,200 $2,500-$2,700
mm mm mm mm
(A) Severance tax per mcfe is based on NYMEX prices of $60.00 per bo and
natural gas prices ranging from $8.70 to $10.00 per mcf during Q3
2005, $60.00 per bo and natural gas prices ranging from $9.25 to
$10.00 per mcf during Q4 2005, $60.00 per bo and natural gas prices
ranging from $8.25 to $10.00 per mcf during calendar 2005 and $50.00
per bo and $7.15 to $7.90 per mcf during calendar 2006.
(B) 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 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
NYMEX Gain Price Open Swap
Strike (Loss) Including Positions as a
Open Price from Open & Assuming Gas % of Estimated
Swaps Of Open Locked Locked Production Total
in Bcf's Swaps Swaps Positions in Bcf's of: Gas Production
2005:
Q3 72.9 $6.64 -$0.15 $6.49 108.0 68%
Q4 79.5 $8.06 -$0.14 $7.92 113.0 70%
Remaining
2005 (A) 152.4 $7.38 -$0.14 $7.24 221.0 69%
2006:
Q1 58.5 $9.38 -$0.15 $9.23 122.0 48%
Q2 44.6 $7.73 -$0.13 $7.60 127.0 35%
Q3 45.1 $7.73 -$0.12 $7.61 132.0 34%
Q4 38.4 $7.82 -$0.12 $7.70 136.0 28%
Total
2006 (A) 186.6 $8.27 -$0.13 $8.14 517.0 36%
Total 2007 14.4 $9.09 -$0.81 $8.28 555.0 3%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 42.6 bcf in 2005 and $3.75 to
$5.50 covering 43.0 bcf in 2006.
Note: Not shown above are collars covering 3.0 bcf of production in 2005
at a weighted average floor and ceiling of $3.59 and $5.37 and 0.2 bcf of
production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70
and call options covering 3.7 bcf of production in 2005 at a weighted average
price of $5.79, 7.3 bcf of production in 2006 at a weighted average price of
$12.50 and 7.3 bcf of production in 2007 at a weighted average price of $12.50
The company has also entered into the following natural gas basis protection
swaps:
Assuming Gas
Production in
Volume in Bcf's NYMEX less*: Bcf's of: % Hedged
3rd & 4th
Quarter 2005 96.3 $ 0.27 221 44%
2006 130.1 0.32 517 25%
2007 126.5 0.28 555 23%
2008 118.6 0.27 580 20%
2009 86.6 0.29 605 14%
Totals 558.1 $ 0.29 2,478 23%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Assuming Oil Open Swap Positions
Open Swaps Avg. NYMEX Production as % of Total
in mbo's Strike Price in mbo's of: Estimated Production
2005:
Q3 903.5 $51.66 1,950 46%
Q4 1,073.5 $54.97 1,950 55%
Remaining
2005 (A) 1,977.0 $53.46 3,900 51%
2006:
Q1 1,035.0 $59.64 1,900.0 54%
Q2 1,016.5 $59.57 1,920.0 53%
Q3 966.0 $59.85 1,940.0 50%
Q4 920.0 $59.55 1,940.0 47%
Total 2006(A) 3,937.5 $59.65 7,700.0 51%
Total 2007 635.0 $54.29 7,750.0 8%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $26.00 to $42.00 covering 552 mbo in 2005 and $40.00 to
$42.00 covering 501.5 mbo in 2006.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF SEPTEMBER 7, 2005
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF OCTOBER 3, 2005
Quarter Ending September 30, 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
September 7, 2005, we are using the following key assumptions in our
projections for the third quarter of 2005, the full-year 2005 and the full-
year 2006.
The primary changes from our August 4, 2005 Outlook are in italicized bold
in the table and are explained as follows:
1) We have updated the projected effect of changes in our hedging
positions since our August 4, 2005 Outlook.
2) We have updated our expectations for future NYMEX oil and gas prices
based on current market conditions in order to illustrate hedging
effects only.
3) We have updated certain of our costs to reflect changing market
conditions.
4) We have included the effects of refinancing amounts outstanding under
our revolving credit facility with the issuance of $600 million of
our 6.5% Senior Notes which occurred in August 2005.
5) We have included the projected effects of refinancing amounts
outstanding on our revolving credit facility with the issuance of
8 million shares of common stock and $250 million of preferred stock.
Quarter Ending Year Ending Year Ending
September 30, 2005 December 31, 2005 December 31, 2006
Estimated
Production:
Oil - Mbo 1,950 7,650 7,700
Gas - Bcf 107-109 411-417 465-475
Gas Equivalent -
Bcfe 118.5-120.5 457-463 511-521
Daily gas
equivalent
midpoint -
in Mmcfe 1,300 1,260 1,414
NYMEX Prices (for
calculation of
realized hedging
effects only):
Oil - $/Bo $61.34 $56.09 $50.00
Gas - $/Mcf $8.53 $7.64 $7.00
Estimated Differentials
to NYMEX Prices:
Oil - $/Bo -$4.50 -$4.46 -$4.50
Gas - $/Mcf -$0.80 -$0.75 -$0.80
Estimated Realized
Hedging Effects
(based on expected
NYMEX prices above):
Oil - $/Bo -$4.48 -$4.13 $4.94
Gas - $/Mcf -$1.21 -$0.32 $0.48
Operating Costs per
Mcfe of Projected
Production:
Production
expense $0.68-0.72 $0.68-0.72 $0.72-0.77
Production taxes
(generally 7%
of O&G
revenues) (A) $0.51-0.56 $0.45-0.50 $0.45-0.50
General and
administrative $0.10-0.12 $0.10-0.12 $0.11-0.13
Stock-based
compensation
(non-cash) $0.03-0.05 $0.03-0.05 $0.04-0.06
DD&A - oil
and gas $1.85-1.95 $1.80-1.90 $2.00-2.10
Depreciation of
other assets $0.09-0.11 $0.09-0.11 $0.10-0.12
Interest
expense (B) $0.48-0.52 $0.45-0.49 $0.45-0.50
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
(approximately
equal to 95%
deferred) 36.5% 36.5% 36.5%
Equivalent Shares
Outstanding:
Basic 322 mm 318 mm 332 mm
Diluted 376 mm 370 mm 389 mm
Capital
Expenditures:
Drilling,
leasehold and
seismic $485-$535 mm $1,900-$2,100 mm $2,100-$2,300 mm
(A) Severance tax per mcfe is based on NYMEX prices of $60.00 per bo and
natural gas prices ranging from $8.70 to $10.00 per mcf during Q3
2005, $55.00 per bo and natural gas prices ranging from $8.25 to
$10.00 per mcf during calendar 2005 and $50.00 per bo and $7.15 to
$7.90 per mcf during calendar 2006.
(B) 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 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
NYMEX Gain Price Open Swap
Strike (Loss) Including Positions as a
Open Price from Open & Assuming Gas % of Estimated
Swaps Of Open Locked Locked Production Total
in Bcf's Swaps Swaps Positions in Bcf's of: Gas Production
2005:
Q3 72.9 $6.64 -$0.15 $6.49 108.0 68%
Q4 78.0 $7.94 -$0.13 $7.81 110.8 70%
Remaining
2005 (A) 150.9 $7.31 -$0.14 $7.17 218.8 69%
2006:
Q1 56.3 $9.19 -$0.15 $9.04 110.0 51%
Q2 41.4 $7.51 -$0.13 $7.38 115.0 36%
Q3 41.9 $7.52 -$0.13 $7.39 120.0 35%
Q4 35.4 $7.57 -$0.13 $7.44 125.0 28%
Total
2006 (A) 175.0 $8.07 -$0.14 $7.93 470.0 37%
Total 2007 11.7 $8.55 -$0.99 $7.56 505.0 2%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 42.6 bcf in 2005 and $3.75 to
$5.50 covering 35.7 bcf in 2006.
Note: Not shown above are collars covering 3.0 bcf of production in 2005
at a weighted average floor and ceiling of $3.59 and $5.37 and 0.2 bcf of
production in 2006 at a weighted average floor and ceiling of $6.00 and $9.70
and call options covering 3.7 bcf of production in 2005 at a weighted average
price of $5.79.
The company has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Production in
Volume in Bcf's NYMEX less*: Bcf's of: % Hedged
Remaining
2005 96.3 $ 0.27 218.8 44%
2006 130.1 0.32 470.0 28%
2007 126.5 0.28 505.0 25%
2008 118.6 0.27 530.0 22%
2009 86.6 0.29 555.0 16%
Totals 558.1 $ 0.29 2,278.8 24%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Assuming Oil Open Swap Positions
Open Swaps Avg. NYMEX Production as % of Total
in mbo's Strike Price in mbo's of: Estimated Production
2005:
Q3 903.5 $51.66 1,950 46%
Q4 1,073.5 $54.97 1,942 55%
Remaining
2005 (A) 1,977.0 $53.46 3,892 51%
2006:
Q1 1,035.0 $59.64 1,900.0 54%
Q2 1,016.5 $59.57 1,920.0 53%
Q3 966.0 $59.85 1,940.0 50%
Q4 920.0 $59.55 1,940.0 47%
Total
2006 (A) 3,937.5 $59.65 7,700.0 51%
Total 2007 635.0 $54.29 7,750.0 8%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $26.00 to $42.00 covering 552 mbo in 2005 and $40.00 to
$42.00 covering 501.5 mbo in 2006.
SOURCE Chesapeake Energy Corporation
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Related links:
http://www.chkenergy.com
CONTACT:
investors, Jeffrey L. Mobley, CFA, Vice
President-Investor Relations and Research, +1-405-767-4763, or
jmobley@chkenergy.com , or media, Thomas S. Price, Jr., Senior
Vice President-Corporate Development, +1-405-879-9257, or
tprice@chkenergy.com , both of Chesapeake Energy Corporation
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