powerpointtext.htm

Petroleum Development Corporation

The following information contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on Management’s current expectations and beliefs, as well as a number of assumptions concerning future events.

These statements are based on certain assumptions and analyses made by Management in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. However, whether actual results and developments will conform with Management’s expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be presented to and pursued by Petroleum Development Corporation; actions by competitors; changes in laws or regulations; and other factors, many of which are beyond the control of Petroleum Development Corporation.

You are cautioned not to put undue reliance on such forward-looking statements because actual results may vary materially from those expressed or implied, as more fully discussed in our safe harbor statements found in our SEC filings, including, without limitation, the discussion under the heading “Risk Factors” in the company’s annual report on Form 10-K. All forward-looking statements are based on information available to Management on this date and Petroleum Development Corporation assumes no obligation to, and expressly disclaims any obligation to, update or revise any forward looking statements, whether as a result of new information, future events or otherwise.

The SEC permits oil and gas companies to disclose in their filings with the SEC only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The Company uses in this presentation the terms “probable” and “possible” reserves, which SEC guidelines prohibit in filings of U.S. registrants. Probable reserves are unproved reserves that are more likely than not to be recoverable. Possible reserves are unproved reserves that are less likely to be recoverable than probable reserves. Estimates of probable and possible reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by the Company. In addition, the Company’s production forecasts and expectations for future periods 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.

This material also contains certain non-GAAP financial measures as defined under the Securities and Exchange Commission rules.

·	Celesta Miracle, VP Investor Relations and Communications

o	Steve Williams, Chairman and CEO

o	Rick McCullough, Vice Chairman and CFO

o	Eric Stearns, Executive Vice President of Exploration and Production

See Slide 2 regarding Forward Looking Statements

Presentation Overview

·	YE 2007 snapshot, history and elements of strategy

·	Areas of operations, opportunities and operating parameters, reserves

·	Preliminary 2007 Results, 2008 Guidance, 2008-2010 Outlook

See Slide 2 regarding Forward Looking Statements

Steve Williams, Chairman and CEO

·	Market Cap (12/31/07)

·	2007 Year-end Proved Reserves 686 Bcfe

·	3-P Reserves @ YE2007

·	Annual Production

o	2007 Proved Reserves: 559 Bcfe

o	2006 Production: 14.1 Bcfe

o	2007 Production: 23.5 Bcfe

o	2007 Proved Reserves: 24 Bcfe

o	Production: 1.4 Bcfe

o	Production: 1.7 Bcfe

o	Exploratory project

o	December 2007/January drilling- 2 horizontal wells

·	Appalachian Basin

o	2006 Proved Reserves: 103 Bcfe

o	2006 Production: 1.5 Bcfe

o	Production: 2.7 Bcfe

See Slide 2 regarding Forward Looking Statements

See Slide 27 regarding reserves included in probably and possible categories.

PDC Investment Theme

o	Large inventory of low-risk, high quality development prospects in Colorado

o	Staff and expertise to predictably execute the development plan

o	Capital to fund development at aggressive 2007 levels through 2010

·	The Company is positioned for significant value creation in 2008 and beyond without any additions to its prospect inventory

·	Acquisitions, exploration or exploitation success in the Barnett or Marcellus shale or other new areas will add to anticipated future reserves and production levels

See Slide 2 regarding Forward Looking Statements

Additional 2008 Value Enhancers

·	Improving margin on production

o	Increased Rocky Mountain gas pricing with start-up of Rocky Mountain Express pipeline (December 2007)

o	G&A unit costs decreasing with increasing production rates

o	Production unit costs decreasing with increasing production rates

·	Potential exploration and exploitation success in new areas

·	Possible acquisitions

See Slide 2 regarding Forward Looking Statements

·	Priced $203 million of senior notes due in 2018 at 12%

·	Announced Company will not offer a 2008 drilling partnership

·	Sold Bakken Shale acreage in North Dakota for $34.7 million

·	Named Rick McCullough to succeed Steve Williams as CEO later in 2008

·	Considering formation of MLP

·	Monitoring market developments

See Slide 2 regarding Forward Looking Statements

·	Pre 2007 growth was through partnerships and drilling and acquisitions

o	High growth with low financial risk

o	Began E&P transition in 2002

·	$354 million Piceance sale in July 2006 was a transformational event

o	$ 192M in acquisitions completed in early 2007 through like-kind exchange

o	Monetized unrecognized value

o	Increased 2007 capital expenditures to ~$270 million from $148 Million in 2006

o	Increasing use of debt in capital structure

·	E&P will underpin future growth

o	Accelerated development of high-quality prospect inventory

o	Bolt-on acquisitions

o	Limited exploration (~10% of capital budget)

See Slide 2 regarding Forward Looking Statements

·	Business divided into four main segments :

o	Oil and Gas Sales

o	Drilling and Development

o	Natural Gas Marketing

See Slide 2 regarding Forward Looking Statements

Business Segment Contribution {Graphic}

·	Decreasing relative impact of Drilling and Development and increasing impact of Oil & Gas Sales reflect transition from drilling program syndicator to E&P company away from partnership syndication

See Slide 2 regarding Forward Looking Statements

Core Operating Regions {Graphic}

2007 Proved Reserves:	559 Bcfe
2006 Production:	14.1 Bcfe
2007 Production:	23.5 Bcfe

2007 Proved Reserves:	24 Bcfe
2006 Production:	1.4 Bcfe
2007 Production:	1.7 Bcfe

2007 Proved Reserves:	103 Bcfe
2006 Production:	1.5 Bcfe
2007 Production:	2.7 Bcfe

See Slide 2 regarding Forward Looking Statements

Energy Market Exposure {Graphic}

Percentage of Sales by Market (Sales in Mcf equivalents as of 9/30/07)

Oil:	21.6%
Northern Border:	0.5%
Midcontinent:	14.3%
Colorado Liquids:	3.0%
Nymex Gas:	12.4%
Michigan:	5.9%
Colorado:	42.3%

See Slide 2 regarding Forward Looking Statements

Consistent Growth {Graphic}

·	PDC has had consistent reserve and production growth through developmental drilling, opportunistic acquisitions and focusing on core operational efficiencies

See Slide 2 regarding Forward Looking Statements

·	Low risk drilling inventory results in high completion rates

	Total Wells
	Total		% Productive
Year	Drilled	Net	Drilled	Net
2002	70.0	13.7	100%	100%
2003	111.0	29.5	99%	97%
2004	158.0	45.0	96%	98%
2005	242.0	110.7	97%	95%
2006	231.0	137.7	97%	97%
2007	343.0	277.0	95%	96%

See Slide 2 regarding Forward Looking Statements

YE2007 Proved Reserve Summary

·	Added to Reserves and Production through acquisitions and development in 2007

·	2007 acquisitions added 195 Bcfe proved reserves

Summary Reserve Data
	Proved Reserves (Bcfe) (1)
	2006 YE	2007 YE	% Growth	% Developed	% Natural Gas
Rockies	175.5	558.6	195%	47.0%	83.6%
Appalachia	36.0	102.7	185%	72.4%	99.8%
Michigan	21.2	24.3	15%	100%	98.6%
Total	322.7	685.6	112%	53.6%	86.6%

1)	Independent reserve engineer’s estimates

See Slide 2 regarding Forward Looking Statements

·	Over 358 Bcfe of Probable and Possible Reserves for Future Development

o	Grand Valley offset locations

o	Wattenberg field locations (5th spot, rule 318A and 40 acre locations)

o	Locations identified by seismic and offsets to producing wells in NE Colorado

{Graphic} Distribution of 2P and 3P Reserves

o	Piceance Basin 57%

o	Wattenberg Field 28%

See Slide 2 regarding Forward Looking Statements

See Slide 2 regarding reserve estimate limitations

·	Proven Track Record

o	5-year 940% return to shareholders through stock price appreciation (1/03- 12/07)

o	66% year-over-year production growth (2006-2007)

o	112% year-over-year reserve growth (2006-2007)

·	Visible Built-in-Growth

o	More than 1 Tcfe of 3P reserves provides significant near-term growth potential

o	Large multi-year, low risk drilling inventory

o	Investments in new areas with substantial growth potential

·	Strong Financial Position

o	Strong balance sheet

o	Debt-to-cap 27% (12/31/2007)

See Slide 2 regarding Forward Looking Statements

·	PDC’s primary goal is to create economic value by continuing to grow reserves, production, net income and cash flow

·	To increase these key performance measures

o	PDC maintains an active drilling program focusing on low-risk development of gas and oil reserves

o	Acquires producing properties with development potential

o	Limited exploratory drilling

See Slide 2 regarding Forward Looking Statements

·	Develop operations in core areas

o	Integrate and accelerate development of legacy and acquired properties

·	Identify and execute strategic acquisitions

o	Bolt-on acquisitions in core areas

o	Acquisitions with similar geologic and operational characteristics to bootstrap new areas

·	Pursue select high potential exploration and exploitation opportunities

·	Maintain focus on increasing long-term stakeholder value

See Slide 2 regarding Forward Looking Statements

Eric Stearns, EVP, Exploration & Production

2007 Operations Highlights

Operations CAPEX	$261M
Net Production	28 Bcfe
Proved Reserves	686 Bcfe
Total 3P Reserves	1.04 Tcfe
Wells Drilled	356 Gross 278 Net
Re-Completions/Fracs	165 Gross 160 Net

See Slide 2 regarding Forward Looking Statements

Development Net Capital	$224M
Exploration, Land, G&G	$24M
Misc. Capital	$12M
Total Net Capital	$261M

See Slide 2 regarding Forward Looking Statements

2007 Production Summary

2007 Forecast by Area (MMcfe)

Area	1Q Actual	1Q Forecast	2Q Actual	2Q Forecast	3Q Actual	3Q Forecast	4Q Actual	4Q Forecast	Total Actual	Total Forecast
Rocky Mtn	4,290	4,435	5,322	5,041	6,683	6,794	7232	7,405	23,527	23,675
Appalachian	617	625	687	640	610	680	830	689	2,744	2,634
Michigan	426	415	427	424	428	456	423	459	1,704	1,754
Total	5,333	5,475	6,436	6,105	7,721	7,930	8,485	8,553	27,975	28,063

2007 Rocky Mountain Forecast by Area (MMcfe)

Area	1Q Actual	1Q Forecast	2Q Actual	2Q Forecast	3Q Actual	3Q Forecast	4Q Actual	4Q Forecast	Total Actual	Total Forecast
Wattenberg	2,209	2,314	2,623	2,586	2,963	3,149	3337	3,361	11,132	11,410
Grand Valley	1,246	1,064	1,590	1,245	2,622	2,086	2770	2,094	8,228	6,489
NECO	677	834	942	954	960	1,203	1030	1,492	3,609	4,483
North Dakota	158	224	165	256	138	355	95	458	556	1,293
Total	4,290	4,436	5,320	5,041	6,683	6,793	7,232	7,405	23,525	23,675

See Slide 2 regarding Forward Looking Statements

YE2007 Proved Reserves

	MMcfe	MMcf Gas	Mbo Oil
Proved Developed	367,688	314,123	8,927
		85%	15%
Proved Undeveloped	317,904	279,440	6,411
		88%	12%
Total Proved	685,592	593,563	15,338
		87%	13%

·	Net Weighted Average Oil Price $80 / Bbl

·	Net Weighted Average Gas Price $6.75 / Mcf

o	Year-end Nymex less applicable area differential

See Slide 2 regarding Forward Looking Statements

YE2007 3P Reserve Summary

	Proved Dev Producing			Proved Dev Non-Producing			Proved Undeveloped			Probable			Possible
	Oil	Gas	Mmcfe	Oil	Gas	Mmcfe	Oil	Gas	Mmcfe	Oil	Gas	Mmcfe	Oil	Gas	Mmcfe
Appalachian Basin	35	59,295	59,502	0	21,060	21,060	0	22,115	22,115	0	0	0	0	0	0
Michigan	58	23,492	23,839	0	487	487	0	0	0	0	0	0	0	0	0
Wattenberg	4,633	42,762	70,558	3,840	24,465	47,507	6,210	40,729	77,988	7,102	43,354	85,965	1,446	6,953	15,629
Piceance	99	83,126	83,718	8	8,201	8,250	201	200,988	202,204	148	148,478	149,369	55	54,705	55,034
NE Colorado	0	43,330	43,330	0	7,612	7,612	0	15,598	15,598	0	27,468	27,468	0	24,860	24,860
ND Bakken Shale	138	29	854	0	0	0	0	0	0	0	0	0	0	0	0
ND Burbak Nesson	106	263	902	0	0	0	0	0	0	0	0	0	0	0	0
Powder River Basin	5	0	29	0	0	0	0	0	0	0	0	0	0	0	0
ND Non-Operated	6	2	40	0	0	0	0	0	0	0	0	0	0	0	0
Total All Fields	5,079	252,298	282,771	3,849	61,825	84,916	6,411	279,440	317,904	7,250	219,299	262,801	1,501	86,518	95,523

	Proved Developed			Total Proved			Total 2P			Total 3P
	Oil	Gas	Mmcfe	Oil	Gas	Mmcfe	Oil	Gas	Mmcfe	Oil	Gas	Mmcfe
Appalachian Basin	35	80,355	80,563	35	102,470	102,678	35	102,470	102,678	35	102,470	102,678
Michigan	58	23,979	24,326	58	23,979	24,326	58	23,979	24,326	58	23,979	24,326
Wattenberg	8,473	67,227	118,065	14,683	107,956	196,052	21,784	151,310	282,017	23,231	158,263	297,646
Piceance	107	91,327	91,968	308	292,324	294,171	456	440,802	443,540	511	495,507	498,573
NE Colorado	0	50,942	50,942	0	66,540	66,540	0	94,007	94,007	0	118,867	118,867
ND Bakken Shale	138	29	854	138	29	854	138	29	854	138	29	854
ND Burbak Nesson	106	263	902	106	263	902	106	263	902	106	263	902
Powder River Basin	5	0	29	5	0	29	5	0	29	5	0	29
ND Non-Operated	6	2	40	6	2	40	6	2	40	6	2	40
Total All Fields	8,927	314,123	367,688	15,338	593,563	685,592	22,588	812,862	948,393	24,089	899,380	1,043,915

See Slide 2 regarding Forward Looking Statements

2007 Drilling Summary (Operated Wells)

Operating Area	Gross Wells	Net Wells
Appalachia	8	8
Michigan	3	3
Wattenberg	153	110
Grand Valley	53	42
NECO	122	111
North Dakota	3	2
Texas	1	1
Non-Operated	13	1
Total	356	278

See Slide 2 regarding Forward Looking Statements

Historical Drilling Activity {Graphic}

2007 Re-Completion Summary

Area	# Projects	# Net Projects
Appalachian	30	30
Wattenberg Codell	45	44
Wattenberg Niobrara	62	61
Wattenberg Cod / Nio	28	25
Total	165	160

See Slide 2 regarding Forward Looking Statements

2006-2007 Acquisition Summary

	DJ Acquisitions	Partnership Buy-Back	Castle
Purchase Price	$160M	$58M	$53M
YE2007 Proved Reserves	105 Bcfe	50e Bcfe	31 Bcfe
Total 3P Reserves	152 Bcfe	50e Bcfe	47 Bcfe
Purchased Wells	379	Interest in 718	741
Drilled wells 2007	106
Re-Work Projects	89
Net Acres Acquired	20,200		39,640
Developed	7,662		29,640
Undeveloped	12,583		10,000
Proved Drilling Locations	266		188
Proved Re-Works	172
Probable Projects	394		32

See Slide 2 regarding Forward Looking Statements

2008 Operations Forecast

	2007	2008	%Change
Development Net Capital (MM$)	224	194	-13%
Exploration, Land, G&G (MM$)	24	50	109%
Miscellaneous Capital (MM$)	12	11	-8%
Total Net Capital (MM$)	$261	$255	-2%

See Slide 2 regarding Forward Looking Statements

2008 Operation and Production Forecast

CAPEX	$255M ($194M Drilling & Re-Works)
Net Production	38 Bcfe
Proved Reserves	750+ Bcfe
Total 3P Reserves	1.2+ Tcfe
Wells Drilled*	360 Gross / 330 Net
Re-Completions/Fracs	130 Gross / 116 Net

See Slide 2 regarding Forward Looking Statements

Operations Forecast 2008 vs 2007

	2007	2008	% Change
Total Net Production (BCFE)	28	38	36%
Net Exit Rate (MMCFE/D)	100	122	22%
Gross Exit Rate (MMCFE/D)	187	211	13%
Development Net Capital (MM$)	$224	$194	-13%
Number of Drilling Projects Gross (Net)*	356 (278)	360 (330)	5% (19%)
Number of Other Projects Gross (Net)*	165 (160)	130 (116)	-21% (-28%)

* Does not include exploitation / exploration wells

See Slide 2 regarding Forward Looking Statements

2008 Estimated Production

Gas, Mmcf	1Q08	2Q08	3Q08	4Q08	Total
Castle	258	270	370	426	1,324
Appalachian	712	727	789	833	3,061
Michigan	383	382	382	378	1,526
Wattenberg	1,901	2,035	2,012	2,043	7,991
Piceance	2,817	2,782	3,443	3,723	12,765
NECO	1,077	1,370	1,583	1,735	5,765
Bakken	2	1	1	1	6
Nesson	10	17	14	21	63
Powder River	0	0	0	0	0
ND Non-Op	0	0	0	0	0
Total	7,159	7,585	8,595	9,161	32,500

Oil, Mbbl	1Q08	2Q08	3Q08	4Q08	Total
Castle	0	0	0	0	0
Appalachian	1	1	1	1	3
Michigan	1	1	1	1	4
Wattenberg	198	218	222	234	872
Piceance	3	3	2	2	10
NECO	0	0	0	0	0
Bakken	4	3	3	3	13
Nesson	3	8	7	12	30
Powder River	0	0	0	0	1
ND Non-Op	0	0	0	0	0
Total	209	234	237	252	932

Mmcfe	1Q08	2Q08	3Q08	4Q08	Total
Castle	258	270	370	426	1,324
Appalachian	716	732	793	838	3,078
Michigan	389	388	387	383	1,547
Wattenberg	3,088	3,344	3,347	3,446	13,224
Piceance	2,833	2,797	3,457	3,736	12,824
NECO	1,077	1,370	1,583	1,735	5,765
Bakken	23	21	20	18	83
Nesson	28	66	54	91	240
Powder River	1	1	1	1	4
ND Non-Op	1	1	1	1	3
Total	8,414	8,990	10,014	10,674	38,092

See Slide 2 regarding Forward Looking Statements

Projected 2008 Production {Graphic}

Proposed Development Projects {Graphic}

2008 Operations by Area

Area	Drilling * Gross (Net)	Re-Works Gross (Net)	Net Production (Bcfe)	Operated Wells YE07
Appalachian	23 (23)	30 (25)	3.1	1361
Michigan	2 (2)		1.5	209
Wattenberg	115 (92)	100 (91)	13.2	1212
Grand Valley	42 (36)		12.8	227
NECO	125 (125)		5.8	457
North Dakota	3 (2)		0.4	7
Texas Barnett				1
Castle	50 (50)		1.3	741
Total	364 (334)	130 (116)	38.1	4215

* Does not include exploitation / exploration wells

See Slide 2 regarding Forward Looking Statements

AREA	Lease Gross Acres	Lease Net Acres	Net Developed Acres	Net Undeveloped Acres	State
Grand Valley	7,804	7,804	2,994	4,810	Colorado
Wattenberg	64,953	63,486	47,440	13,143	Colorado
Neco	80,000	51,000	16,800	34,200	Colorado
Neco	24,539	23,000	1,880	21,120	Kansas
Michigan	8,680	8,680	8,240	440	Michigan
New York	19,500	16,575	0	16,575	New York
North Dakota	101,267	68,474	4,767	59,972	North Dakota
Appalachian Basin	54,600	54,600	54,600	0	WV / PA
Castle Gas	39,640	39,640	29,640	10,000	Pennsylvania
Wyoming	31,945	31,945	0	31,945	Wyoming
Texas Barnett	10,804	8,868	0	8,868	Texas
Total	443,732	374,072	166,361	201,073

		PDC TOTAL NET		367,434

See Slide 2 regarding Forward Looking Statements

2008 Rockies Operating Areas

·	Greater Wattenberg Field Area, DJ Basin

o	Adams, Weld County, Colorado

§	Niobrara, Codell, J Sand

·	Grand Valley Field, Piceance Basin

o	Garfield County, Colorado

§	Mesaverde Section

·	NECO Area, eastern DJ Basin

o	Yuma County, Colorado & Cheyenne County, KS

·	North Dakota, Western Williston Basin

§	Nesson, Midale, Bakken

See Slide 2 regarding Forward Looking Statements

IP Rate	1250 Mcfe/d
Production Profile	Hyperbolic
EUR	1500 Mmcfe
Life of Well	24.5 years
Severance Tax	2.05%
Ad Valorem Tax	3.43%
Production Expense	$2900/mo & $0.10/mcf
Gas Index	80% CIG; 20% MidCon
Gathering	($0.41)
BTU Factor	1.067
Fuel	3.9%
Capital Cost of Well	$2300k
Net Direct F&D Cost	$1.87/Mcfe
Working Interest	100%
NRI	82%

Operated wells year end	1212
Undeveloped acreage	13,143
Number of remaining net locations	914
Net PUD	325
Net Probable	476
Net Possible	50

	2007	2008	% Change
Total Net Production (BCFE)	11.1	13.2	19%
Net Exit Rate (MMCFE/D)	36.6	40.4	10%
Total Net Capital (MM$)	$90.9	$61.6	-32%
Drilling Projects, Gross (Net)	153 (110)	115 (92)	-25%
Other Projects, Gross (Net)	135 (130)	100 (91)	-26%

	2007	2008	% Change
Total Net Production (BCFE)	2.5	3.1	24%
Net Exit Rate (MMCFE/D)	7.0	9.1	30%
Total Net Capital (MM$)	$5.0	$8.9	78%
Drilling Projects, Gross (Net)	8 (8)	23 (23)	130%
Other Projects, Gross (Net)	30 (30)	30 (25)	0%

Operated Wells year end	7
Undeveloped Acreage	59,972
Number of remaining locations
PUD	0

	MM$
Exploration	11.4
Exploitation	13.7
G & G	6.1
Land	19.2
Total	$50.4

	2008	2009	2010
Total Net Capital (MM$)	254	315	315
Net Production (BCFE)	38	48	56
% Production Growth	36%	26%	17%
Gross Drilling Projects	360	360	360
Net Drilling Projects	330	358	358

	2007 Guidance ($MM)	2007 Actual ($MM)
Revenues	$167 – 197	$170 - 200
Expenses
DD&A	58 – 65	70 – 75
G&A	14 – 16	28 – 30
Operating Income	82 – 95	63 – 75
Net Income	47 – 54	36 – 42

			Floors		Ceilings		Swaps (Fixed Prices)
Hedging Schedule (as of 2/4/08)	Begin	End	Monthly Qty MMBtu	Floor Price	Monthly Qty MMBtu	Ceiling Price	Monthly Qty MMBtu	Fixed Price
Colorado Interstate Gas (CIG) Based Derivatives (Piceance Basin)
	Nov-07 Nov-07 Apr-08 Apr-08 Nov-08 Apr-09	Mar-08 Mar-08 Oct-08 Oct-08 Mar-09 Oct-09	100,000 100,000 197,250 - 272,600 272,600	$5.25 $5.25 $5.50 - $6.50 $5.75	- 100,000 197,250 - 272,600 272,600	- $9.80 $10.35 - $10.15 $8.75	- - - 294,000 - -	- - - $6.54 - -
NYMEX Based Derivatives (Appalachian & Michigan Basins)
	Nov-07 Nov-07 Apr-08 Apr-08 Nov-08 Apr-09	Mar-08 Mar-08 Oct-08 Oct-08 Mar-09 Oct-09	144,500 144,500 144,500 120,000 123,000 123,000	$7.00 $7.00 $6.50 $7.00 $7.50 $6.75	- 144,500 144,500 120,000 123,000 123,000	- $13.70 $10.80 $13.00 $14.20 $12.45	-	-
Panhandle Based Derivatives (NECO)
	Nov-07 Nov-07 Apr-08 Apr-08 Apr-08 Nov-08 Apr-09	Mar-08 Mar-08 Oct-08 Oct-08 Oct-08 Mar-09 Oct-09	70,000 90,000 90,000 90,000 - 110,000 100,000	$5.75 $6.00 $5.50 $6.00 - $6.75 $6.00	- 90,000 90,000 90,000 - 110,000 110,000	- $11.25 $9.85 $11.25 - $10.05 $9.70	- - - - 120,000 - -	- - - - $6.80 - -
Colorado Interstate Gas (CIG) Based Derivatives (Wattenberg Basin)
	Nov-07 Apr-08 Apr-08 Nov-08 Apr-09	Mar-08 Oct-08 Oct-08 Mar-09 Oct-09	120,000 306,000 - 199,800 199,800	$5.25 $5.50 - $6.50 $5.75	120,000 306,000 - 199,800 199,800	$9.80 $10.35 - $10.15 $8.75	- - 206,000 - -	- - $6.54
Oil – NYMEX Based (Wattenberg Basin)
	Jan-08 Jan-09 Jan-09 Jan-10 Jan-10	Dec-08 Dec-09 Dec-09 Dec-10 Dec-10	- - - 18,700 18,700	- - - $70.00 $70.00	- - - 18,700 18,700	- - - $102.25 $103.00	29,070 18,700 18,700 - -	$84.20 $84.90 $85.40 - -

	Codell / Niobrara	Codell
IP Rate	295 Mcfe/d	195 Mcfe/d
Production Profile	Hyperbolic	Hyperbolic
EUR	300 Mmcfe	200 Mmcfe
Life of Well	23.5 years	9.5 years
Severance Tax	2.05%	2.05%
Ad Valorem Tax	5.54%	5.54%
Production Expense	$612 / month	$612 / month
Gas Index	CIG	CIG
Gathering	$0.00	$0.00
BTU Factor	1.000	1.000
Fuel	0.0%	0.0%
Capital Cost of Well	$610k	$510k
Working Interest	100%	100%
NRI	80%	80%
Net F&D Cost	$2.54 / Mcfe	$3.19 / Mcfe

IP Rate	109 Mcfe/d
Production Profile	Hyperbolic
EUR	185 Mmcfe
Life of Well	27 years
Severance Tax	2.05%
Ad Valorem Tax	5.54%
Production Expense	$612 / month
Gas Index	CIG
Gathering	$0.00
BTU Factor	1.000
Fuel	0.0%
Capital Cost of Well	$195k
Working Interest	100%
NRI	80%
Net F&D Cost	$1.32 / Mcfe

IP Rate	92 Mcf/d
Production Profile	Hyperbolic
EUR	192 MMcf
Life of Well	27.92 years
Severance Tax	2.05%
Ad Valorem Tax	5.91%
Production Expense	$685 / month
Gas Index	20% MidCon; 80% CIG
Gathering	($0.45)
BTU Factor	1.000
Fuel	4.8%
Capital Cost of Well	$250k
Working Interest	100%
NRI	80%
Net F&D Cost	$1.62 / Mcfe

IP Rate	59 Mcf/d
Production Profile	Hyperbolic
EUR	177 MMcf
Life of Well	59.1 years
Severance Tax	5.0% and $0.047/mcf
Ad Valorem Tax	3.0%
Production Expense	$552 / month
Gas Index	DTI Appal. Index
Gathering	$0.00
BTU Factor	1.07
Fuel	12%
Capital Cost of Well	$330k
Working Interest	100%
NRI	87.50%
Net F&D Cost	$2.33 / Mcfe

IP Rate	44 Mcf/d
Production Profile	Hyperbolic
EUR	75 MMcf
Life of Well	30.6 years
Severance Tax	5.0% and $0.047/mcf
Ad Valorem Tax	3.0%
Production Expense	$544 / month
Gas Index	DTI Appal. Index
Gathering	$0.00
BTU Factor	1.07
Fuel	12.0%
Capital Cost of Well	$75k
Working Interest	100%
NRI	87.50%
Net F&D Cost	$1.00 / Mcfe

IP Rate	72 Mcf/d
Production Profile	Hyperbolic
EUR	189 MMcf
Life of Well	40.1 years
Severence Tax	0.0%
Ad Valorem Tax	0.0%
Production Expense	$250 / month
Gas Index	DTI Appal. Index
Gathering	$0.00
BTU Factor	1.07
Fuel	0.0%
Capital Cost of Well	$253k
Working Interest	100%
NRI	81.25%
Net F&D Cost	$1.67 / Mcfe