Average						Average
		Barrels		Floor/Ceiling				MMBtu		Average
Term		Per Day		Prices		Term		Per Day		Price
Crude Oil Sales (NYMEX WTI) Collars						Natural Gas Sales (NYMEX HH TO CIG) Basis Swaps
Full year 2008		1,000		$70.00 / $76.70		1st Quarter 2008		16,000		$1.74
Full year 2008		10,000		$47.50 / $70.00		2nd Quarter 2008		17,000		$1.43
Full year 2009		10,000		$47.50 / $70.00		3rd Quarter 2008		19,000		$1.40
Full year 2009		295		$80.00 / $91.00		4th Quarter 2008		21,000		$1.46
Full year 2010		1,000		$60.00 / $80.00
Full year 2010		1,000		$55.00 / $76.20		Natural Gas Sales (NYMEX HH) Swaps
Full year 2010		1,000		$55.00 / $77.75		1st Quarter 2008		16,200		$8.04
Full year 2010		1,000		$55.00 / $77.70		2nd Quarter 2008		16,200		$8.04
Full year 2010		1,000		$55.00 / $83.10		3rd Quarter 2008		16,200		$8.04
Full year 2010		1,000		$60.00 / $75.00		4th Quarter 2008		16,200		$8.04
Full year 2010		1,000		$65.15 / $75.00
Full year 2010		1,000		$65.50 / $78.50		Natural Gas Sales (NYMEX HH) Collars				Floor/Ceiling Prices
Full year 2010		280		$80.00 / $90.00		2nd Quarter 2008		800		$7.50 / $8.40
Full year 2011		270		$80.00 / $90.00		3rd Quarter 2008		2,800		$7.50 / $8.50
						4th Quarter 2008		4,800		$8.00 / $9.50
Crude Oil Sales (NYMEX WTI) Swaps
Full year 2008		260		$74.00
Full year 2008		335		$92.00
Full year 2009		240		$71.50

Payments to our counterparties are triggered when the monthly average prices are above the swap or ceiling price in the case of our crude oil and natural gas sales hedges and below the swap price for our natural gas sales basis hedge positions. Conversely, payments from our counterparties are received when the monthly average prices are below the swap or floor price for our crude oil and natural gas sales hedges and above the swap price for our natural gas sales basis hedge positions.

As of February 26, 2008, we entered into gas swaps for 15,400 MMBtu/D at $8.50 for the full year of 2009 and basis swaps on the same volumes for average prices of $1.17, $1.12, $.97 and $1.05 for the first, second, third and fourth quarters of 2009, respectively.

The collar strike prices will allow us to protect a significant portion of our future cash flow if 1) oil prices decline below our floor prices which range from $47.50 to $80.00 per barrel while still participating in any oil price increase up to the ceiling prices which range from $70.00 to $91.00 per barrel on the volumes indicated above, and if 2) gas prices decline below our floor prices which range from $7.50 to $8.00 per MMBtu while still participating in any gas price increase up to the ceiling prices, which range from $8.40 to $9.50 per MMBtu on the respective volumes. These hedges improve our financial flexibility by locking in significant revenues and cash flow upon a substantial decline in crude oil or natural gas prices, including certain basis differentials. It also allows us to develop our long-lived assets and pursue exploitation opportunities with greater confidence in the projected economic outcomes and allows us to borrow a higher amount under our senior unsecured revolving credit facility.

While we have designated our hedges as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, it is possible that a portion of the hedge related to the movement in the WTI to California heavy crude oil price differential may be determined to be ineffective. Likewise, we may have some ineffectiveness in our natural gas hedges due to the movement of HH pricing as compared to actual sales points. If this occurs, the ineffective portion will directly impact net income rather than being reported as Other Comprehensive Income (Loss). If the differential were to change significantly, it is possible that our hedges, when marked-to-market, could have a material impact on earnings in any given quarter and, thus, add increased volatility to our net income. The marked-to-market values reflect the liquidation values of such hedges and not necessarily the values of the hedges if they are held to maturity.

We entered into derivative contracts (natural gas swaps and collar contracts) in March 2006 that did not qualify for hedge accounting under SFAS 133 because the price index for the location in the derivative instrument did not correlate closely with the item being hedged. These contracts were recorded in the first quarter of 2006 at their fair value on the Balance Sheet and we recognized an unrealized net loss of approximately $4.8 million on the Statements of Income under the caption “Commodity derivatives.” We entered into natural gas basis swaps on the same volumes and maturity dates as the previous hedges in May 2006 which allowed for these derivatives to be designated as cash flow hedges going forward, causing an unrealized net gain of $5.6 million to be recognized in the second quarter of 2006. The difference of $.8 million was recorded in other comprehensive income at the date the hedges were designated.

Additionally, 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.

The related cash flow impact of all of our derivative activities are reflected as cash flows from operating activities.

Irrespective of the unrealized gains reflected in Other Comprehensive Income, the ultimate impact to net income over the life of the hedges will reflect the actual settlement values. All of these hedges have historically been deemed to be cash flow hedges with the marked-to-market valuations provided by external sources, based on prices that are actually quoted.

At December 31, 2007, Accumulated Other Comprehensive Loss, net of income taxes, consisted of $121 million of unrealized losses from our crude oil and natural gas hedges. Deferred net losses recorded in Accumulated Other Comprehensive Loss at December 31, 2007 are expected to be reclassified to earnings over the life of the contracts. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. With respect to our hedging activities, we utilize multiple counterparties on our hedges and monitor each counterparty's credit rating.

		2007				2006				2005
Net reduction of sales of oil and gas revenue due to hedging activities (in millions)		$	21.8			$	15.7			$	45.3
Net reduction of cost of gas due to hedging activities (in millions)		$	-			$	1.6			$	5.0
Net reduction in revenue per BOE due to hedging activities		$	2.21			$	1.71			$	5.39

Based on NYMEX futures prices as of December 31, 2007 (WTI $88.34; HH $7.81), we would expect to make pre-tax future cash payments or to receive payments over the remaining term of our crude oil and natural gas hedges in place as follows: 

					Impact of percent change in futures prices
		12/31/07			on earnings
			NYMEX Futures			-20%			-10%			+10%			+20%
Average WTI Futures Price (2008 - 2011)		$	88.34		$	70.67		$	79.50		$	97.17		$	106.00
Average HH Futures Price (2008)			7.81			6.24			7.03			8.59			9.37
Crude Oil gain/(loss) (in millions)			(186.5	)		(15.8	)		(92.0	)		(285.8	)		(386.2	)
Natural Gas gain/(loss) (in millions)			.5			10.7			5.5			(4.1	)		(9.2	)
Total		$	(186.0	)	$	(5.1	)	$	(86.5	)	$	(289.9	)	$	(395.4	)
Net pretax future cash (payments) and receipts by year (in millions) based on average price in each year:
2008 (WTI $93.71; HH $7.81)		$	(94.3	)	$	(5.4	)	$	(49.6	)	$	(138.6	)	$	(183.3	)
2009 (WTI $88.39)			(68.6	)		(2.0	)		(35.5	)		(102.3	)		(136.3	)
2010 (WTI $85.83)			(23.1	)		1.2			(1.7	)		(48.7	)		(74.6	)
2011 (WTI $85.41)			-			1.1			.3			(.3	)		(1.2	)
Total		$	(186.0	)	$	(5.1	)	$	(86.5	)	$	(289.9	)	$	(395.4	)

Interest Rates. Our exposure to changes in interest rates results primarily from long-term debt. In October 2006, we issued $200 million of 8.25% senior subordinated notes due 2016 in a public offering. Total long-term debt outstanding at December 31, 2007 and 2006 was $445 million and $390 million, respectively. Interest on amounts borrowed under our revolving credit facility is charged at LIBOR plus 1.0% to 1.75%, with the exception of the $100 million of principal for which we have a hedge in place to fix the interest rate at approximately 5.5% plus the senior unsecured revolving credit facility’s margin through June 30, 2011. Based on year end 2007 credit facility borrowings, a 1% change in interest rates would have a $1 million after tax impact on our financial statements.

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