Attached files
| file | filename |
|---|---|
| 8-K - CURRENT REPORT - CHESAPEAKE ENERGY CORP | chk01042010_8k.htm |
| EX-99.3 - PRESS RELEASE - DECEMBER 28, 2009 - CHESAPEAKE ENERGY CORP | chk12282009_993.htm |
| EX-99.1 - PRESS RELEASE - JANUARY 4, 2010 - CHESAPEAKE ENERGY CORP | chk01042010_991.htm |
Exhibit 99.2
SCHEDULE
“A”
CHESAPEAKE’S
OUTLOOK AS OF JANUARY 4, 2010
Years
Ending December 31, 2010 and 2011
Our
policy is to periodically provide guidance on certain factors that affect our
future financial performance. As of January 4, 2010, we are using the
following key assumptions in our projections for 2010 and 2011.
The
primary changes from our November 2, 2009 Outlook are in italicized
bold and are explained as follows:
|
1)
|
Projected
production volumes have been updated to reflect the production loss from
the expected sale of 25% of our Barnett assets to Total (initially
approximately 175 mmcfe per day) and production gains from the ongoing
outperformance of our drilling programs. We believe these two factors will
cancel each other in 2010 and therefore our 2010 production guidance
remains unchanged at 2,650 mmcfe per day. However, we have
increased our 2011 production forecast by 50 mmcfe per day to
reflect the anticipated ongoing outperformance of our drilling
programs;
|
|
2)
|
Projected
effects of changes in our hedging positions have been updated;
and
|
|
3)
|
Our
cash flow projections have been
updated.
|
|
Year
Ending
12/31/2010
|
Year
Ending
12/31/2011
|
||||||
|
Estimated
Production:
|
|||||||
|
Natural
gas – bcf
|
882
– 902
|
1,022
– 1,047
|
|||||
|
Oil
– mbbls
|
12,500
|
13,000
|
|||||
|
Natural
gas equivalent – bcfe
|
957
– 977
|
1,100
– 1,125
|
|||||
|
Daily
natural gas equivalent midpoint – mmcfe
|
2,650
|
3,050
|
|||||
|
Year-over-year
estimated production increase
|
6
– 8%
|
14
– 16%
|
|||||
|
Year-over-year
estimated production increase excluding divestitures and
curtailments
|
12
– 14%
|
15
– 17%
|
|||||
|
NYMEX
Price (for calculation of realized hedging effects only):
|
|||||||
|
Natural
gas - $/mcf
|
$7.00
|
$7.50
|
|||||
|
Oil
- $/bbl
|
$80.00
|
$80.00
|
|||||
|
Estimated
Realized Hedging Effects (based on assumed NYMEX prices
above):
|
|||||||
|
Natural
gas - $/mcf
|
$0.70
|
$0.23
|
|||||
|
Oil
- $/bbl
|
$4.74
|
$8.30
|
|||||
|
Estimated
Differentials to NYMEX Prices:
|
|||||||
|
Natural
gas - $/mcf
|
15
– 25%
|
15
– 25%
|
|||||
|
Oil
- $/bbl
|
7 –
10%
|
7 –
10%
|
|||||
|
Operating
Costs per Mcfe of Projected Production:
|
|||||||
|
Production
expense
|
$0.90
– 1.10
|
$0.90
– 1.10
|
|||||
|
Production
taxes (~ 5% of O&G revenues)
|
$0.30
– 0.35
|
$0.30
– 0.35
|
|||||
|
General
and administrative(a)
|
$0.33
– 0.37
|
$0.33
– 0.37
|
|||||
|
Stock-based
compensation (non-cash)
|
$0.10
– 0.12
|
$0.10
– 0.12
|
|||||
|
DD&A
of natural gas and oil assets
|
$1.50
– 1.70
|
$1.50
– 1.70
|
|||||
|
Depreciation
of other assets
|
$0.20
– 0.25
|
$0.20
– 0.25
|
|||||
|
Interest
expense(b)
|
$0.35
– 0.40
|
$0.35
– 0.40
|
|||||
|
Other
Income per Mcfe:
|
|||||||
|
Marketing,
gathering and compression net margin
|
$0.07
– 0.09
|
$0.07
– 0.09
|
|||||
|
Service
operations net margin
|
$0.04
– 0.06
|
$0.04
– 0.06
|
|||||
|
Equity
in income of midstream joint venture (CMP)
|
$0.04
– 0.06
|
$0.04
– 0.06
|
|||||
|
Book
Tax Rate (all deferred)
|
39%
|
39%
|
|||||
|
Equivalent
Shares Outstanding (in millions):
|
|||||||
|
Basic
|
625
– 630
|
635
– 640
|
|||||
|
Diluted
|
640
– 645
|
645
– 650
|
|||||
|
Year
Ending
12/31/2010
|
Year
Ending
12/31/2011
|
|||
|
Cash
Flow Projections ($ in millions):
|
||||
|
Operating
cash flow before changes in assets and
liabilities(c)(d)
|
$4,450
– 4,750
|
$5,000
– 5,600
|
||
|
Net
leasehold and producing property transactions
|
$1,300
– 1,700
|
$1,000 – 1,300
|
||
|
Drilling
capital expenditures
|
($4,000
– 4,300)
|
($4,100
– 4,400)
|
||
|
Dividends,
capitalized interest, cash income taxes, etc.
|
($350
– 400)
|
($450
– 550)
|
||
|
Other
|
($500
– 600)
|
($250
– 300)
|
||
|
Projected
Net Cash Change
|
$900
– 1,150
|
$1,200
– 1,650
|
||
At
December 31, 2009, the company had approximately $2.5 billion of
cash and cash equivalents and additional borrowing capacity under its three
revolving bank credit facilities.
|
(a)
|
Excludes
expenses associated with noncash stock compensation.
|
|
(b)
|
Does
not include gains or losses on interest rate derivatives (ASC
815).
|
|
(c)
|
A
non-GAAP financial measure. We are unable to provide a
reconciliation to projected cash provided by operating activities, the
most comparable GAAP measure, because of uncertainties associated with
projecting future changes in assets and liabilities.
|
|
(d)
|
Assumes
NYMEX natural gas prices of $6.50 to $7.50 per mcf and NYMEX oil prices of
$80.00 per bbl in 2010 and NYMEX natural gas prices of $ 7.00
to $8.00 per mcf and NYMEX oil prices of $80.00 per bbl in
2011.
|
Commodity
Hedging Activities
The
company utilizes hedging strategies to hedge the price of a portion of its
future natural gas and oil production. These strategies
include:
|
1)
|
Swaps:
Chesapeake receives a fixed price and pays a floating market price to the
counterparty for the hedged commodity.
|
|
2)
|
Collars:
These instruments contain a fixed floor price (put) and ceiling price
(call). If the market price exceeds the call strike price or
falls below the put strike price, Chesapeake receives the fixed price and
pays the market price. If the market price is between the put
and the call strike price, no payments are due from either
party. On occasion, we make a three-way collar by selling an
additional put option with the collar in exchange for a more favorable
strike price on the collar. This eliminates the counterparty’s
downside exposure below the second put option.
|
|
3)
|
Knockout
swaps: Chesapeake receives a fixed price and pays a floating market
price. The fixed price received by Chesapeake includes a
premium in exchange for the possibility to reduce the counterparty’s
exposure to zero, in any given month, if the floating market price is
lower than certain pre-determined knockout prices.
|
|
4)
|
Call
options: Chesapeake receives a premium from the counterparty in exchange
for the sale of a call option. If the market price exceeds the
fixed price of the call option, Chesapeake pays the counterparty such
excess. If the market price settles below the fixed price of
the call option, no payment is due from either party.
|
|
5)
|
Basis
protection swaps: These instruments are arrangements that guarantee a
price differential to NYMEX for natural gas from a specified delivery
point. For non-Appalachian Basin basis protection swaps, which
typically have negative differentials to NYMEX, 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. For
Appalachian Basin basis protection swaps, which typically have positive
differentials to NYMEX, Chesapeake receives a payment from the
counterparty if the price differential is less than the stated terms of
the contract and pays the counterparty if the price differential is
greater than the stated terms of the
contract.
|
All of
our derivative instruments are net settled based on the difference between the
fixed-price payment and the floating-price payment, resulting in a net amount
due to or from the counterparty.
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 natural gas and oil derivative transactions in order to mitigate a
portion of its exposure to adverse market changes in natural gas and oil
prices. Accordingly, associated gains or losses from the derivative
transactions are reflected as adjustments to natural gas and oil
sales. All realized gains and losses from natural gas and oil
derivatives are included in natural gas and oil sales in the month of related
production. Pursuant to ASC 815, certain derivatives do not qualify
for designation as cash flow hedges. Changes in the fair value of
these nonqualifying 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 natural
gas and oil sales. Following provisions of ASC 815, 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 natural gas and oil sales.
The
company currently has the following open natural gas swaps in place and also has
the following gains from lifted natural gas trades:
|
Open
Swaps
(Bcf)
|
Avg.
NYMEX
Strike
Price
of
Open
Swaps
|
Assuming
Natural
Gas Production
(Bcf)
|
Open
Swap
Positions
as
a % of
Estimated
Total
Natural
Gas Production
|
Total
Gains
from
Lifted
Trades
($
millions)
|
Total
Lifted
Gain
per
Mcf
of
Estimated
Total
Natural
Gas
Production
|
||||||||
|
Q1
2010
|
97
|
$7.46
|
$35.9
|
||||||||||
|
Q2
2010
|
99
|
$7.27
|
$37.9
|
||||||||||
|
Q3
2010
|
94
|
$7.54
|
$65.7
|
||||||||||
|
Q4
2010
|
96
|
$7.69
|
$65.2
|
||||||||||
|
Total
2010(a)
|
386
|
$7.49
|
892
|
43%
|
$204.7
|
$0.23
|
|||||||
|
Total
2011(a)
|
64
|
$8.69
|
1,035
|
6%
|
$62.7
|
$0.06
|
|
(a)
|
Certain
hedging arrangements include knockout swaps with provisions limiting the
counterparty’s exposure at $5.50 to $6.75 covering 15 bcf in 2010 and
$5.75 to 6.50 covering 24 bcf in
2011.
|
The
company currently has the following open natural gas collars in
place:
|
Open
Collars
(Bcf)
|
Avg.
NYMEX
Floor
Price
|
Avg.
NYMEX
Ceiling
Price
|
Assuming
Natural
Gas
Production
(Bcf)
|
Open
Collars
as
a % of
Estimated
Total
Natural
Gas
Production
|
||||||
|
Q1
2010
|
43
|
$6.49
|
$8.51
|
|||||||
|
Q2
2010
|
16
|
$7.04
|
$9.17
|
|||||||
|
Q3
2010
|
4
|
$7.60
|
$11.75
|
|||||||
|
Q4
2010
|
4
|
$7.60
|
$11.75
|
|||||||
|
Total
2010(a)
|
67
|
$6.75
|
$9.03
|
892
|
8%
|
|||||
|
Total
2011
|
7
|
$7.70
|
$11.50
|
1,035
|
1%
|
|
(a)
|
Certain
collar arrangements include three-way collars that include written put
options with a strike price ranging from $4.25 to $4.35 covering 12 bcf in
2010.
|
The
company currently has the following natural gas written call options in
place:
|
Call
Options
(Bcf)
|
Avg.
NYMEX
Floor
Price
|
Avg.
Premium
per
mcf
|
Assuming
Natural
Gas
Production
(Bcf)
|
Call
Options
as
a % of
Estimated
Total
Natural
Gas
Production
|
||||||
|
Q1
2010
|
28
|
$10.19
|
$1.47
|
|||||||
|
Q2
2010
|
38
|
$9.87
|
$1.11
|
|||||||
|
Q3
2010
|
43
|
$9.93
|
$0.98
|
|||||||
|
Q4
2010
|
43
|
$10.10
|
$0.98
|
|||||||
|
Total
2010
|
152
|
$10.01
|
$1.10
|
892
|
17%
|
|||||
|
Total
2011
|
73
|
$10.25
|
$0.57
|
1,035
|
7%
|
The
company has the following natural gas basis protection swaps in
place:
|
Non-Appalachia
|
Appalachia
|
|||||||
|
Volume
(Bcf)
|
NYMEX
less(a)
|
Volume
(Bcf)
|
NYMEX
plus(a)
|
|||||
|
2010
|
—
|
—
|
10
|
0.26
|
||||
|
2011
|
45
|
0.82
|
12
|
0.25
|
||||
|
2012
|
43
|
0.85
|
—
|
—
|
||||
|
Totals
|
88
|
$0.84
|
22
|
$0.26
|
||||
|
(a)
|
weighted
average
|
The
company also has the following crude oil swaps in place:
|
Open
Swaps
(mbbls)
|
Avg.
NYMEX
Strike
Price
|
Assuming
Oil
Production
(mbbls)
|
Open
Swap
Positions
as a %
of
Estimated
Total
Oil Production
|
Total
Gains
(Losses)
from
Lifted
Trades
($
millions)
|
Total
Lifted
Gains
(Losses)
per
bbl of
Estimated
Total
Oil
Production
|
||||||
|
Q1
2010
|
1,980
|
$89.56
|
—
|
—
|
$(4.0)
|
—
|
|||||
|
Q2
2010
|
2,002
|
$89.56
|
—
|
—
|
$(4.0)
|
—
|
|||||
|
Q3
2010
|
2,024
|
$89.56
|
—
|
—
|
$(4.2)
|
—
|
|||||
|
Q4
2010
|
2,024
|
$89.56
|
—
|
—
|
$(4.2)
|
—
|
|||||
|
Total
2010(a)
|
8,030
|
$89.56
|
12,500
|
64%
|
$(16.4)
|
$(1.31)
|
|||||
|
Total
2011(a)
|
3,285
|
$96.09
|
13,000
|
25%
|
$32.8
|
$2.53
|
|
(a)
|
Certain
hedging arrangements include knockout swaps with provisions limiting the
counterparty’s exposure below prices of $60.00 covering 5 mmbbls and 1
mmbbls in 2010 and 2011,
respectively.
|
Note: Not
shown above are written call options covering 3 mmbbls of oil production in 2010
at a weighted average price of $105.00 per bbl for a weighted average discount
of $1.10 per bbl and 4 mmbls of oil production in 2011 at a weighted average
price of $105.00 per bbl for a weighted average premium of $4.27 per
bbl.
SCHEDULE
“B”
CHESAPEAKE’S
PREVIOUS OUTLOOK AS OF NOVEMBER 2, 2009
(PROVIDED
FOR REFERENCE ONLY)
NOW
SUPERSEDED BY OUTLOOK AS OF JANURARY 4, 2010
Years
Ending December 31, 2009, 2010 and 2011
Our
policy is to periodically provide guidance on certain factors that affect our
future financial performance. As of November 2, 2009, we are using
the following key assumptions in our projections for 2009, 2010 and
2011.
The
primary changes from our October 13, 2009 Outlook are in italicized
bold and are explained as follows:
|
1)
|
Projected
effects of changes in our hedging positions have been
updated;
|
|
2)
|
Our
NYMEX natural gas and oil price assumptions for realized hedging effects
and estimating future operating cash flow have been updated;
and
|
|
3)
|
Our
cash flow projections have been
updated.
|
|
Year
Ending
12/31/2009
|
Year
Ending
12/31/2010
|
Year
Ending
12/31/2011
|
|||||||
|
Estimated
Production:
|
|||||||||
|
Natural
gas – bcf
|
815
– 825
|
882
– 902
|
1,007
– 1,027
|
||||||
|
Oil
– mbbls
|
12,000
|
12,500
|
13,000
|
||||||
|
Natural
gas equivalent – bcfe
|
885
– 895
|
957
– 977
|
1,085
– 1,105
|
||||||
|
Daily
natural gas equivalent midpoint – mmcfe
|
2,440
|
2,650
|
3,000
|
||||||
|
Year-over-year
estimated production increase
|
5 –
6%
|
8 –
10%
|
12
– 14%
|
||||||
|
Year-over-year
estimated production increase excluding divestitures and
curtailments
|
9 –
10%
|
10
– 12%
|
13
– 15%
|
||||||
|
NYMEX
Prices
(a) (for calculation of realized hedging effects
only):
|
|||||||||
|
Natural
gas - $/mcf
|
$3.91
|
$7.00
|
$7.50
|
||||||
|
Oil
- $/bbl
|
$57.75
|
$80.00
|
$80.00
|
||||||
|
Estimated
Realized Hedging Effects (based on assumed NYMEX prices
above):
|
|||||||||
|
Natural
gas - $/mcf
|
$2.97
|
$0.85
|
$0.22
|
||||||
|
Oil
- $/bbl
|
$3.78
|
$1.99
|
$5.71
|
||||||
|
Estimated
Differentials to NYMEX Prices:
|
|||||||||
|
Natural
gas - $/mcf
|
20
– 30%
|
15
– 25%
|
15
– 25%
|
||||||
|
Oil
- $/bbl
|
7 –
10%
|
7 –
10%
|
7 –
10%
|
||||||
|
Operating
Costs per Mcfe of Projected Production:
|
|||||||||
|
Production
expense
|
$1.10
– 1.20
|
$0.90
– 1.10
|
$0.90
– 1.10
|
||||||
|
Production
taxes (~ 5% of O&G revenues)(b)
|
$0.20
– 0.25
|
$0.30
– 0.35
|
$0.30
– 0.35
|
||||||
|
General
and administrative(c)
|
$0.33
– 0.37
|
$0.33
– 0.37
|
$0.33
– 0.37
|
||||||
|
Stock-based
compensation (non-cash)
|
$0.10
– 0.12
|
$0.10
– 0.12
|
$0.10
– 0.12
|
||||||
|
DD&A
of natural gas and oil assets
|
$1.50
– 1.70
|
$1.50
– 1.70
|
$1.50
– 1.70
|
||||||
|
Depreciation
of other assets
|
$0.25
– 0.30
|
$0.20
– 0.25
|
$0.20
– 0.25
|
||||||
|
Interest
expense(d)
|
$0.30
– 0.35
|
$0.35
– 0.40
|
$0.35
– 0.40
|
||||||
|
Other
Income per Mcfe:
|
|||||||||
|
Marketing,
gathering and compression net margin
|
$0.10
– 0.12
|
$0.07
– 0.09
|
$0.07
– 0.09
|
||||||
|
Service
operations net margin
|
$0.04
– 0.06
|
$0.04
– 0.06
|
$0.04
– 0.06
|
||||||
|
Equity
in income of midstream joint venture (CMP)
|
–
|
$0.04
– 0.06
|
$0.04
– 0.06
|
||||||
|
Book
Tax Rate (all deferred)
|
37.5%
|
39%
|
39%
|
||||||
|
Equivalent
Shares Outstanding (in millions):
|
|||||||||
|
Basic
|
610
– 615
|
625
– 630
|
635
– 640
|
||||||
|
Diluted
|
625
– 630
|
640
– 645
|
645
– 650
|
||||||
|
Year
Ending
12/31/2009
|
Year
Ending
12/31/2010
|
Year
Ending
12/31/2011
|
||||
|
Cash
Flow Projections ($ in millions):
|
||||||
|
Operating
cash flow before changes in assets and
liabilities(e)(f)
|
$3,700
– 3,750
|
$4,350
– 5,050
|
$4,750
– 5,450
|
|||
|
Net
leasehold and producing property transactions
|
$750
– 900
|
$1,000
– 1,350
|
$900
– 1,250
|
|||
|
Drilling
capital expenditures
|
($3,150
– 3,350)
|
($4,400
– 4,700)
|
($4,600
– 4,900)
|
|||
|
Dividends,
senior notes redemption, capitalized
interest, cash income taxes,
etc.
|
($600
– 825)
|
($400
– 500)
|
($450
– 550)
|
|||
|
Other
|
($375
– 550)
|
($225
– 300)
|
($50
– 125)
|
|||
|
Projected
Net Cash Change
|
($75)
– 325
|
$325
– 900
|
$550
– 1,125
|
|||
At
September 30, 2009, the company had $3.1 billion of cash and cash equivalents
and additional borrowing capacity under its three revolving bank credit
facilities.
|
(a)
|
NYMEX
natural gas prices have been updated for actual contract prices through
November 2009 and NYMEX oil prices have been updated for actual contract
prices through September 2009.
|
|
(b)
|
Production
tax per mcfe is based on NYMEX prices of $57.75 per bbl of oil and $4.75
to $6.25 per mcf of natural gas during 2009 and $80.00 per bbl of oil and
$7.00 to $8.25 per mcf of natural gas during 2010 and
2011.
|
|
(c)
|
Excludes
expenses associated with noncash stock compensation.
|
|
(d)
|
Does
not include gains or losses on interest rate derivatives (ASC
815).
|
|
(e)
|
A
non-GAAP financial measure. We are unable to provide a
reconciliation to projected cash provided by operating activities, the
most comparable GAAP measure, because of uncertainties associated with
projecting future changes in assets and liabilities.
|
|
(f)
|
Assumes
NYMEX natural gas prices of $5.00 to $6.00 per mcf and NYMEX oil prices of
$57.75 per bbl in 2009, NYMEX natural gas prices of $6.50 to
$7.50 per mcf and NYMEX oil prices of $80.00 per bbl in 2010
and NYMEX natural gas prices of $ 7.00 to $8.00 per mcf and
NYMEX oil prices of $80.00 per bbl in
2011.
|
Commodity
Hedging Activities
The
company utilizes hedging strategies to hedge the price of a portion of its
future natural gas and oil production. These strategies
include:
|
1)
|
For
swap instruments, Chesapeake receives a fixed price for the commodity and
pays a floating market price to the counterparty.
|
|
2)
|
Collars
contain a fixed floor price (put) and ceiling price (call). If
the market price exceeds the call strike price or falls below the put
strike price, Chesapeake receives the fixed price and pays the market
price. If the market price is between the call and the put
strike price, no payments are due from either party.
|
|
3)
|
For
knockout swaps, Chesapeake receives a fixed price and pays a floating
market price. The fixed price received by Chesapeake includes a
premium in exchange for the possibility to reduce the counterparty’s
exposure to zero, in any given month, if the floating market price is
lower than certain pre-determined knockout prices.
|
|
4)
|
For
written call options, Chesapeake receives a premium from the counterparty
in exchange for the sale of a call option. If the market price
exceeds the fixed price of the call option, Chesapeake pays the
counterparty such excess. If the market price settles below the
fixed price of the call option, no payment is due from
Chesapeake.
|
|
5)
|
Basis
protection swaps are arrangements that guarantee a price differential to
NYMEX for natural gas from a specified delivery point. For
non-Appalachian Basin basis protection swaps, which typically have
negative differentials to NYMEX, 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. For Appalachian Basin
basis protection swaps, which typically have positive differentials to
NYMEX, Chesapeake receives a payment from the counterparty if the price
differential is less than the stated terms of the contract and pays the
counterparty if the price differential is greater than the stated terms of
the contract.
|
|
6)
|
A
three-way collar contract consists of a standard collar contract plus a
written put option with a strike price below the floor price of the
collar. In addition to the settlement of the collar, the put
option requires Chesapeake to make a payment to the counterparty equal to
the difference between the put option price and the settlement price if
the settlement price for any settlement period is below the put option
strike price.
|
All of
our derivative instruments are net settled based on the difference between the
fixed-price payment and the floating-price payment, resulting in a net amount
due to or from the counterparty.
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 natural gas and oil derivative transactions in order to mitigate a
portion of its exposure to adverse market changes in natural gas and oil
prices. Accordingly, associated gains or losses from the derivative
transactions are reflected as adjustments to natural gas and oil
sales. All realized gains and losses from natural gas and oil
derivatives are included in natural gas and oil sales in the month of related
production. Pursuant to ASC 815, certain derivatives do not qualify
for designation as cash flow hedges. Changes in the fair value of
these nonqualifying 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 natural
gas and oil sales. Following provisions of ASC 815, 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 natural gas and oil sales.
Excluding
the swaps assumed in connection with the acquisition of CNR which are described
below, the company currently has the following open natural gas swaps in place
and also has the following gains from lifted natural gas trades:
|
Open
Swaps
(Bcf)
|
Avg.
NYMEX
Strike
Price
of
Open
Swaps
|
Assuming
Natural
Gas Production
(Bcf)
|
Open
Swap
Positions
as
a % of
Estimated
Total
Natural
Gas Production
|
Total
Gains
from
Lifted
Trades
($
millions)
|
Total
Lifted
Gain
per
Mcf
of
Estimated
Total
Natural
Gas
Production
|
||||||||
|
Q4
2009(a)
|
107.2
|
$6.83
|
210
|
51%
|
$114.2
|
$0.54
|
|||||||
|
Q1
2010
|
28.7
|
$9.84
|
$50.6
|
||||||||||
|
Q2
2010
|
27.5
|
$8.83
|
$52.7
|
||||||||||
|
Q3
2010
|
31.7
|
$9.60
|
$60.1
|
||||||||||
|
Q4
2010
|
33.0
|
$9.77
|
$59.5
|
||||||||||
|
Total
2010(a)
|
120.9
|
$9.53
|
892
|
14%
|
$222.9
|
$0.25
|
|||||||
|
Total
2011(a)
|
23.7
|
$9.86
|
1,017
|
2%
|
$62.7
|
$0.06
|
|
(a)
|
Certain
hedging arrangements include knockout swaps with provisions limiting the
counterparty’s exposure at $6.00 covering 1 bcf for the remainder of 2009,
$5.45 to $6.75 covering 70 bcf in 2010 and $5.75 to 6.50 covering 24 bcf
in 2011.
|
The
company currently has the following open natural gas collars in
place:
|
Open
Collars
(Bcf)
|
Avg.
NYMEX
Floor
Price
|
Avg.
NYMEX
Ceiling
Price
|
Assuming
Natural
Gas
Production
(Bcf)
|
Open
Collars
as
a % of
Estimated
Total
Natural
Gas
Production
|
||||||
|
Q4
2009(a)
|
52.1
|
$7.34
|
$8.88
|
210
|
25%
|
|||||
|
Q1
2010
|
43.2
|
$6.49
|
$8.51
|
|||||||
|
Q2
2010
|
16.4
|
$7.04
|
$9.17
|
|||||||
|
Q3
2010
|
3.7
|
$7.60
|
$11.75
|
|||||||
|
Q4
2010
|
3.7
|
$7.60
|
$11.75
|
|||||||
|
Total
2010(a)
|
67.0
|
$6.75
|
$9.03
|
892
|
8%
|
|||||
|
Total
2011
|
7.2
|
$7.70
|
$11.50
|
1,017
|
1%
|
|
(a)
|
Certain
collar arrangements include three-way collars that include written put
options with a strike price of $6.00 covering 11 bcf for the remainder of
2009 and ranging from $4.25 to $5.50 covering 26 bcf in
2010.
|
The
company currently has the following natural gas written call options in
place:
|
Call
Options
(Bcf)
|
Avg.
NYMEX
Floor
Price
|
Avg.
Premium
per
mcf
|
Assuming
Natural
Gas
Production
(Bcf)
|
Call
Options
as
a % of
Estimated
Total
Natural
Gas
Production
|
||||||
|
Q4
2009
|
9.7
|
$6.51
|
$2.25
|
210
|
5%
|
|||||
|
Q1
2010
|
69.3
|
$10.26
|
$0.61
|
|||||||
|
Q2
2010
|
74.6
|
$10.08
|
$0.56
|
|||||||
|
Q3
2010
|
75.4
|
$10.17
|
$0.56
|
|||||||
|
Q4
2010
|
75.4
|
$10.27
|
$0.56
|
|||||||
|
Total
2010
|
294.7
|
$10.19
|
$0.57
|
892
|
33%
|
|||||
|
Total
2011
|
73.1
|
$10.25
|
$0.57
|
1,017
|
7%
|
The
company has the following natural gas basis protection swaps in
place:
|
Non-Appalachia
|
Appalachia
|
|||||||
|
Volume
(Bcf)
|
NYMEX
less(a)
|
Volume
(Bcf)
|
NYMEX
plus(a)
|
|||||
|
2009
|
10.4
|
$1.64
|
4.4
|
$0.27
|
||||
|
2010
|
—
|
—
|
10.2
|
0.26
|
||||
|
2011
|
45.1
|
0.82
|
12.1
|
0.25
|
||||
|
2012
|
43.2
|
0.85
|
—
|
—
|
||||
|
Totals
|
98.7
|
$0.92
|
26.7
|
$0.26
|
||||
|
(a)
|
weighted
average
|
We
assumed certain liabilities related to open derivative positions in connection
with the CNR acquisition in November 2005. In accordance with ASC
805, these derivative positions were recorded at fair value in the purchase
price allocation as a liability of $592 million ($11 million as of September 30,
2009). The recognition of the derivative liability and other assumed
liabilities resulted in an increase in the total purchase price which was
allocated to the assets acquired. Because of this accounting
treatment, only cash settlements for changes in fair value subsequent to the
acquisition date for the derivative positions assumed result in adjustments to
our natural gas and oil revenues upon settlement. For example, if the
fair value of the derivative positions assumed does not change, then upon the
sale of the underlying production and corresponding settlement of the derivative
positions, cash would be paid to the counterparties and there would be no
adjustment to natural gas and oil revenues related to the derivative
positions. If, however, the actual sales price is different from the
price assumed in the original fair value calculation, the difference would be
reflected as either a decrease or increase in natural gas and oil revenues,
depending upon whether the sales price was higher or lower, respectively, than
the prices assumed in the original fair value calculation. For
accounting purposes, the net effect of these acquired hedges is that we hedged
the production volumes listed below at their fair values on the date of our
acquisition of CNR.
Pursuant
to ASC 815 Derivatives and
Hedging, the assumed CNR derivative instruments are deemed to contain a
significant financing element and all cash flows associated with these positions
are reported as financing activity in the statement of cash flows.
The
following details the CNR derivatives (natural gas swaps) we have
assumed:
|
Open
Swaps
(Bcf)
|
Avg.
NYMEX Strike
Price
Of
Open
Swaps
|
Avg.
Fair
Value
Upon Acquisition of
Open
Swaps
|
Initial
Liability
Acquired
|
Assuming
Natural
Gas
Production
(Bcf)
|
Open
Swap
Positions
as a %
of
Estimated Total
Natural
Gas
Production
|
||||||
|
Q4
2009
|
4.6
|
$5.18
|
$7.32
|
$(2.14)
|
210
|
2%
|
Note: Not
shown above are collars covering 1 bcf of production for the remainder of 2009
at an average floor and ceiling of $4.50 and $6.00.
The
company also has the following crude oil swaps in place:
|
Open
Swaps
(mbbls)
|
Avg.
NYMEX
Strike
Price
|
Assuming
Oil
Production
(mbbls)
|
Open
Swap
Positions
as a %
of
Estimated
Total
Oil Production
|
Total
Gains
(Losses)
from
Lifted
Trades
($
millions)
|
Total
Lifted
Gains
(Losses)
per
bbl of
Estimated
Total
Oil
Production
|
||||||
|
Q4
2009
|
1,058
|
$87.05
|
2,947
|
36%
|
$9.4
|
$3.20
|
|||||
|
Q1
2010
|
1,170
|
$90.25
|
—
|
—
|
$(4.0)
|
—
|
|||||
|
Q2
2010
|
1,183
|
$90.25
|
—
|
—
|
$(4.0)
|
—
|
|||||
|
Q3
2010
|
1,196
|
$90.25
|
—
|
—
|
$(4.2)
|
—
|
|||||
|
Q4
2010
|
1,196
|
$90.25
|
—
|
—
|
$(4.2)
|
—
|
|||||
|
Total
2010(a)
|
4,745
|
$90.25
|
12,500
|
38%
|
$(16.4)
|
$(1.31)
|
|||||
|
Total
2011(a)
|
1,095
|
$104.75
|
13,000
|
8%
|
$32.8
|
$2.53
|
|
(a)
|
Certain
hedging arrangements include knockout swaps with provisions limiting the
counterparty’s exposure below prices ranging from $50.00 to $60.00
covering 1 mmbbls for the remainder of 2009 and $60.00 covering 5 mmbbls
and 1 mmbbls in 2010 and 2011,
respectively.
|
Note: Not
shown above are written call options covering 1 mmbbls of oil production for the
remainder of 2009 at a weighted average price of $112.50 per bbl for a weighted
average discount of $1.21 per bbl, 3 mmbbls of oil production in 2010 at a
weighted average price of $115.00 per bbl for a weighted average discount of
$0.86 per bbl and 4 mmbls of oil production in 2011 at a weighted average price
of $105.00 per bbl for a weighted average premium of $4.27 per
bbl.