Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As discussed in Note 3 to the financial statements, to minimize the effect of a downturn in oil and gas prices and protect our profitability and the economics of our development plans, we enter into crude oil and natural gas hedge contracts from time to time. The terms of contracts depend on various factors, including management's view of future crude oil and natural gas prices, acquisition economics on purchased assets and our future financial commitments. This price hedging program is designed to moderate the effects of a severe crude oil and natural gas price downturn while allowing us to participate in some commodity price increases. In California, we benefit from lower natural gas pricing, as we are a consumer of natural gas in our operations, and elsewhere we benefit from higher natural gas pricing. We have hedged, and may hedge in the future, both natural gas purchases and sales as determined appropriate by management. Management regularly monitors the crude oil and natural gas markets and our financial commitments to determine if, when, and at what level some form of crude oil and/or natural gas hedging and/or basis adjustments or other price protection is appropriate and in accordance with policy established by our board of directors. Currently, our hedges are in the form of swaps and collars. However, we may use a variety of hedge instruments in the future to hedge WTI or the index gas price. The collar strike prices allow us to protect our cash flow if oil prices decline below our floor prices which range from $55.00 to $100.00 per barrel while still participating in any oil price increase up to the ceiling prices which range from $68.00 to $161.10 per barrel on the volumes indicated below. In total, we have approximately 75% and 40% of our expected 2010 and 2011 oil production, respectively, hedged in the form of swaps and collars. Our natural gas collars have a floor of from $6.00 to $6.50 per MMBtu and ceilings ranging from $7.25 to $8.90 per MMBtu. In total, we have approximately 30% and 10% of our 2010 and 2011 expected natural gas production, respectively, hedged in the form of swaps and collars. A ten dollar change in oil prices impacts our annual operating cash flow by approximately $14 million. A one dollar change in natural gas prices impacts annual operating cash flow by approximately $2 million.
The following table summarizes our commodity hedge positions as of December 31, 2009:
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|
Average |
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|
|
|
|
Average |
|
|
||||
|
|
Barrels |
|
Average |
|
|
|
MMBtu |
|
Average |
||||
Term |
|
Per Day |
|
Prices |
|
Term |
|
Per Day |
|
Price |
||||
Crude Oil Sales (NYMEX WTI) Collars |
|
Natural Gas Sales (NYMEX HH) Swaps |
||||||||||||
Full year 2010 |
|
1,000 |
|
$65.15 / $75.00 |
|
Full year 2010 |
|
5,000 |
|
$5.73 |
||||
Full year 2010 |
|
1,000 |
|
$65.50 / $78.50 |
|
Full year 2010 |
|
5,000 |
|
$6.02 |
||||
Full year 2010 |
|
280 |
|
$80.00 / $90.00 |
|
Full year 2011 |
|
5,000 |
|
$6.89 |
||||
Full year 2010 |
|
1,000 |
|
$100.00/$161.10 |
|
Full year 2012 |
|
5,000 |
|
$7.16 |
||||
Full year 2010 |
|
1,000 |
|
$100.00/$150.30 |
|
|
|
|
|
|
||||
Full year 2010 |
|
1,000 |
|
$100.00/$160.00 |
|
Natural Gas Sales (NYMEX HH) Collars |
||||||||
Full year 2010 |
|
1,000 |
|
$100.00/$150.00 |
|
Full year 2010 |
|
2,000 |
|
$6.00/$8.60 |
||||
Full year 2010 |
|
1,000 |
|
$100.00/$158.50 |
|
Full year 2010 |
|
3,000 |
|
$6.00/$8.65 |
||||
Full year 2010 |
|
1,000 |
|
$70.00/$86.00 |
|
Full year 2010 |
|
1,000 |
|
$6.50/$8.75 |
||||
Full year 2011 |
|
270 |
|
$80.00/$90.00 |
|
Full year 2010 |
|
1,000 |
|
$6.50/$8.85 |
||||
Full year 2011 |
|
1,000 |
|
$55.20/$70.00 |
|
Full year 2010 |
|
2,000 |
|
$6.50/$8.90 |
||||
Full year 2011 |
|
1,000 |
|
$55.00/$70.50 |
|
Full year 2011 |
|
5,000 |
|
$6.00/$7.25 |
||||
Full year 2011 |
|
1,000 |
|
$55.00/$68.65 |
|
Full year 2012 |
|
5,000 |
|
$6.00/$7.70 |
||||
Full year 2011 |
|
1,000 |
|
$55.00/$68.00 |
|
|
|
|
|
|
||||
Full year 2011 |
|
1,000 |
|
$55.00/$71.20 |
|
|
||||||||
Full year 2011 |
|
1,000 |
|
$60.00/$76.00 |
|
Natural Gas Sales (NYMEX HH to NGPL-Tex OK) Basis Swaps |
||||||||
Full year 2011 |
|
1,000 |
|
$60.00/$81.25 |
|
Full year 2010 |
|
2,500 |
|
$0.415 |
||||
Full year 2012 |
|
1,000 |
|
$63.00/$82.60 |
|
Full year 2011 |
|
2,500 |
|
$0.460 |
||||
Full year 2012 |
|
1,000 |
|
$63.00/$83.50 |
|
Full year 2012 |
|
2,500 |
|
$0.440 |
||||
Full year 2012 |
|
1,000 |
|
$70.00/$93.00 |
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|
|
|
|
|
||||
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|
|
|
|
|
|
|
|
|
|
||||
Crude Oil Sales (NYMEX WTI) Swaps |
|
Natural Gas Sales (NYMEX HH TO NGPL) Basis Swaps |
||||||||||||
Full year 2010 |
|
1,000 |
|
$61.00 |
|
Full year 2010 |
|
2,000 |
|
$0.49 |
||||
Full year 2010 |
|
1,000 |
|
$61.25 |
|
|
|
|
|
|
||||
Full year 2010 |
|
1,000 |
|
$64.80 |
|
Natural Gas Sales (NYMEX HH TO HSC) Basis Swaps |
||||||||
Full year 2010 |
|
1,000 |
|
$62.03 |
|
Full year 2010 |
|
2,000 |
|
$0.38 |
||||
Full year 2010 |
|
1,000 |
|
$63.00 |
|
Full year 2010 |
|
2,500 |
|
$0.345 |
||||
Full year 2010 |
|
1,000 |
|
$63.75 |
|
Full year 2011 |
|
2,500 |
|
$0.325 |
||||
Full year 2010 |
|
650 |
|
$56.90 |
|
Full year 2012 |
|
2,500 |
|
$0.320 |
||||
Full year 2011 |
|
500 |
|
$57.36 |
|
|
|
|
|
|
||||
Full year 2011 |
|
500 |
|
$57.40 |
|
Natural Gas Sales (NYMEX HH TO PEPL) Basis Swaps |
||||||||
Full year 2010 |
|
500 |
|
$57.50 |
|
Full year 2010 |
|
2,000 |
|
$1.05 |
||||
Full year 2010 |
|
250 |
|
$61.80 |
|
Full year 2010 |
|
3,000 |
|
$1.00 |
||||
We generally utilize NYMEX WTI based derivatives to hedge cash flows from our California oil sales. Our oil sales contracts with multiple refiners are primarily based on the field posting prices. There is a high correlation between WTI and the field posting prices which have historically allowed us to utilize hedge accounting. As there is a ready market for our crude oil in California, we do not believe the loss of any particular refiner impacts the probability that our hedged forecasted transactions will occur. We generally hedge our natural gas at the basis location that corresponds to the sale.
While we have historically designated the majority of our hedges as cash flow hedges, we have not elected hedge accounting on certain of our crude oil and natural gas hedges. During the twelve months ended December 31, 2009, we recorded a gain of $6.5 million under the caption “Gain (loss) on derivatives" related to hedges for which we either did not elect hedge accounting or which no longer qualified for hedge accounting. In conjunction with the sale of the DJ basin assets, during the first quarter of 2009, we concluded that the forecasted transaction in certain of our hedging relationships was not probable of occurring. As such, we reclassified a gain of $14.3 million from AOCL to the statement of income under the caption “Gain (loss) on derivative." “Gain (loss) on derivatives" included a loss for cash settlements of $7.6 million and a gain for the change in fair value of $0.3 million on hedges for which we have not elected hedge accounting. Additionally, a portion of the change in fair value for hedges that we have designated as cash flow hedges may impact our income as our sales price is not perfectly correlated with our hedges. We recognized an unrealized net loss of $0.5 million on the statement of income under the caption “Gain (loss) on derivatives" for the twelve months ended December 31, 2009, as a result of ineffectiveness. During the first quarter of 2009, we entered into natural gas derivatives on behalf of the purchaser of our DJ assets. We did not elect hedge accounting for these hedges and recorded an unrealized net loss of $0.5 million on the statement of income under the caption “(Loss) income from discontinued operations, net of taxes."
We have entered into interest rate hedges as shown below to swap the floating rate under our senior secured credit facility (LIBOR) for a fixed interest rate. These interest rate swaps have been designated as cash flow hedges.
|
|
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Notional |
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|
|
|
|
Amount |
|
|
|
Hedge Term |
|
$MM |
|
Fixed Rate |
|
4/1/2009 – 6/30/2012 |
|
100 |
|
4.74% |
|
4/15/2009 – 7/15/2012 |
|
100 |
|
1.99% |
|
9/15/2009 – 7/15/2012 |
|
50 |
|
2.31% |
The related cash flow impact of all of our hedges is reflected in cash flows from operating activities. At December 31, 2009, our net fair value of derivative liability was $97.4 million as compared to a net fair value asset of $185.9 million at December 31, 2008 which reflects increases in commodity prices. Based on NYMEX strip pricing as of December 31, 2009, we expect to pay cash under the existing derivatives of $21.7 million during the next twelve months. At December 31, 2009, AOCL consisted of $60.4 million, net of tax, of unrealized losses from our crude oil and natural gas swaps and collars that qualified for hedge accounting treatment. Deferred net losses recorded in AOCL at December 31, 2009 and subsequent mark-to-market changes in the underlying hedging contracts are expected to be reclassified to earnings in the same period that the forecasted transaction impacts earnings.
Based on NYMEX futures prices as of December 31, 2009 (WTI $85.13; HH $6.31), we would expect to receive payments over the remaining term of our crude oil and natural gas hedges in place as follows:
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|
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|
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|
|
Impact of percent change in futures prices |
|
|||||||||
|
|
|
|
12/31/09 |
|
|
on pretax future cash (payments) and receipts |
|
|||||||||
|
|
|
|
NYMEX Futures |
|
|
-40% |
|
|
-20% |
|
|
+20% |
|
|
+40% |
|
|
Average WTI Futures Price (2010 – 2012) |
|
$ |
85.13 |
|
$ |
51.08 |
|
$ |
68.10 |
|
$ |
102.16 |
|
$ |
119.18 |
|
|
Average HH Futures Price (2010 – 2012) |
|
|
6.31 |
|
|
3.79 |
|
|
5.05 |
|
|
7.57 |
|
|
8.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil gain/(loss) (in millions) |
|
$ |
(78.3) |
|
$ |
183.5 |
|
$ |
53.9 |
|
$ |
(233.5) |
|
$ |
(367.0) |
|
|
Natural Gas gain/(loss) (in millions) |
|
|
(0.3) |
|
|
38.3 |
|
|
21.9 |
|
|
(3.7) |
|
|
(16.4) |
|
|
Total |
|
$ |
(78.6) |
|
$ |
221.8 |
|
$ |
75.8 |
|
$ |
(237.2) |
|
$ |
(383.4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net pretax future cash (payments) and receipts by year (in millions) based on average price in each year: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 (WTI $81.06; HH $6.01) |
|
$ |
(21.7) |
|
$ |
174.9 |
|
$ |
73.3 |
|
$ |
(111.6) |
|
$ |
(184.0) |
|
|
2011 (WTI $85.51; HH $6.42) |
|
|
(54.0) |
|
|
30.2 |
|
|
(1.9) |
|
|
(115.0) |
|
|
(177.9) |
|
|
2012 (WTI $87.83) |
|
|
(2.9) |
|
|
16.7 |
|
|
4.4 |
|
|
(10.6) |
|
|
(21.5) |
|
|
Total |
|
$ |
(78.6) |
|
$ |
221.8 |
|
$ |
75.8 |
|
$ |
(237.2) |
|
$ |
(383.4) |
|
Interest Rates. Our exposure to changes in interest rates results primarily from long-term debt. In October 2006, we issued, in a public offering, $200 million principal amount of 8.25% senior subordinated notes due 2016. In May 2009, we issued, in a public offering, $325 million of 10.25% senior notes due 2014. In August 2009, we issued, in a public offering, an additional $125 million of 10.25% senior notes due 2014. At December 31, 2009, total long-term debt outstanding was $1.0 billion. Interest on amounts borrowed under our credit facility is charged at LIBOR plus 2.25% to 3.0% plus the credit facility’s margin through July 15, 2012. Based on December 31, 2009 credit facility borrowings, a 1% change in interest rates, including our interest rate hedges, would have an annualized $1.0 million after tax impact on our financial statements.
In June 2006 and July 2006 we entered into five year interest rate swaps for a fixed rate of approximately 5.5% on $100 million of our outstanding borrowings under our credit facility. These interest rate swaps have been designated as cash flow hedges. In 2008, $50 million of these interest rate swaps were extended one year, resulting in a fixed rate of approximately 4.8%. In 2008 we also entered into three year interest rate swaps for a fixed rate of approximately 2.2% on an additional $275 million of our outstanding borrowings under our credit facility for three years beginning on April 15 and September 15, 2009. These interest rate swaps have been designated as cash flow hedges. As of December 31, 2008, we had a total of $575 million of fixed rate positions averaging 4.8% resulting from the $200 million of 8.25% senior subordinated notes and $375 million of interest rate swaps for a fixed rate of approximately 2.2%.
During 2009, we entered into three year interest rates swaps for a fixed rate of approximately 2.1% on an additional $150 million of our outstanding borrowings under our credit facility beginning on April 15 and December 15, 2009. These interest rate swaps have been designated as cash flow hedges. As a result of these 2009 hedge contracts, we have a total of $900 million of fixed rate positions averaging 7.8%.
Effective January 1, 2010, we have elected to de-designate all of our commodity and interest rate contracts that had previously been designated as cash flow hedges as of December 31, 2009 and have elected to discontinue hedge accounting prospectively. At December 31, 2009, AOCL consisted of $97 million ($60 million after tax) of unrealized losses, representing the mark-to-market value of the Company’s cash flow hedges as of the balance sheet date, less any ineffectiveness recognized. As a result of discontinuing hedge accounting on January 1, 2010, such mark-to-market values at December 31, 2009 are frozen in AOCL as of the de-designation date and will be reclassified into earnings in future periods as the original hedged transactions affect earnings. The Company expects to reclassify into earnings from AOCL the frozen value related to de-designated commodity hedges during the next three years.