OF THE STATE OF COLORADO

IN THE MATTER OF ALLEGED VIOLATIONS OF THE RULES THE RULES             )         CAUSE NO. 1V

AND REGULATIONS OF THE COLORADO OIL AND GAS OIL AND GAS                 )

CONSERVATION CONSERVATION COMMISSION BY ENCANA OIL & GAS          )           ORDER NO. 1V-298

(USA) INC. GARFIELD COUNTY, COLORADO                                                               )

                        1. Between January 19, 2001 and March 16, 2001 Ballard Petroleum, LLC ("Ballard") drilled four (4) gas wells on the G33 pad located in the SW¼ NE¼ of Section 33, Township 6 South, Range 92 West, 6^th P.M. These wells are: the Boulton No. 33-2 Well, which was spud on January 19, 2001; the Boulton No. 33-7 Well, which was spud on February 5, 2001; the Boulton No. 33-8 Well, which was spud on February 24, 2001; and the Boulton No. 33-9 Well, which was spud on March 16, 2001. The wells were drilled directionally to the Williams Fork Formation. Drilling reports do not reflect whether there was any observation of shallow natural gas while drilling the Wasatch interval of these wells. Cased hole petrophysical logs were run on each of the wells from April 6-7, 2001, several weeks after primary cementing of and the appearance of bradenhead pressure in the wells. The log records indicate shallow natural gas was present in the Wasatch Formation in each well at the time the logs were run. No other unusual drilling conditions were encountered.

                        2. Effective December 31, 2001, AEC Oil & Gas (USA) Inc. became the operator of the Boulton wells located on the G33 pad. Effective June 1, 2002, EnCana Oil & Gas (USA) Inc. became the operator of the Boulton wells located on the G33 pad.

                        3. A water well formerly co-owned by the Larry Amos and Harland Walker families (the "Water Well", sometimes formerly referred to as the "Amos/Walker water well"), located in the SE¼ of Section 33, Township 6 South, Range 92 West, 6^th P.M., was completed on May 26, 1981 for Divide Creek Land and Cattle Company under Colorado Division of Water Resources water well Permit No. 113065. The total depth of the Water Well is 225 feet below the ground surface (bgs) and at the time of completion, the well had a static water level of 68 feet bgs. The Water Well was permitted as a domestic water well that could be used to supply water to not more than three (3) single family dwellings for normal household purposes, fire protection, and the irrigation of not over one (1) acre of home gardens and lawns. As of 2001, it appears that the Water Well was supplying water to three households, approximately fifty horses, and surface irrigation of more than one acre.

                        4. On April 30, 2001, COGCC staff received a complaint from Mr. Harland Walker (co-owner of the Water Well) that the Water Well had begun to produce smelly, dark gray, "fizzing" water and that the amount of water that the well could produce had decreased. He stated that the Water Well problems began a week or two earlier. On May 1, 2001, the following day, COGCC staff received a similar complaint from Mr. Larry Amos (former co-owner of the Water Well) stating that the well cap had blown off and that gray fizzy water had gushed from the Water Well.

                        5. COGCC staff investigated both of these complaints by conducting site inspections, measuring bradenhead pressures, and performing and overseeing water and gas sampling and analysis. On May 21, 2001 COGCC staff visited the site and observed that the water produced from the Water Well was effervescing with gas and gas could be heard entering the Water Well. (During a COGCC visit on August 28, 2001, the Water Well was not effervescing and gas could not be heard entering the Water Well.) Water samples have been collected by either COGCC staff, or by Cordilleran Compliance Services (Cordilleran) on behalf of the COGCC staff or EnCana, or by ESN Rocky Mountain (ESN) on behalf of EnCana, from the Water Well a number of times. The methane concentration detected in the sample collected on May 4, 2001 was 12 milligrams per liter (mg/l); on May 21, 2001 it was 7.04 mg/l; on August 28, 2001 in the sample collected by COGCC it was 6.0 mg/l; on August 28, 2001 in the sample collected by Cordilleran after purging it was 0.1 mg/l; on March 7, 2003 it was 7.07 mg/l; on January 20, 2004 it was 13 mg/l; on November 11, 2004 it was 14 mg/l; on December 20, 2004 it was 7.9 mg/l; on February 3, 2005 in the sample collected by ESN it was 0.4 mg/l; and on March 17, 2005 it was 7.9 mg/l. Analysis of the stable isotopes of carbon and hydrogen in the methane and compositional analysis were performed on gas samples collected from the Water Well on May 21, 2001, May 21, 2004, July 23, 2004, November 11, 2004, December 20, 2004, and March 17, 2005. The analytical results showed the dissolved gas in the Water Well was thermogenic, but the composition and the stable isotope ratios did not match those of a sample of production gas from the Boulton 33-9 well or a sample of bradenhead gas from the Boulton 33-2 well, both of which were collected on May 21, 2001.

Evaluation of the compositions and the stable isotope ratios of the gas samples indicate that the gas from the Water Well has been degraded by microbes, thus, the specific source of the gas in the Water Well could not be identified. However, when analytical results for samples collected from the Water Well are plotted with the analytical results of produced and bradenhead gas, COGCC staff contends that they plot in a tight cluster of data points indicating a similarity of the gas in the Water Well to the produced and bradenhead gas from gas wells in the area (e.g., wells on the G-33 pad, P-3 pad, and the Schwartz 2-15B well).

                        6. Water samples collected directly from the Water Well, before any treatment, on May 4, 2001, May 21, 2001, August 28, 2001, March 7, 2003, January 20, 2004, November 11, 2004, December 20, 2004, and March 17, 2005 were tested for benzene, toluene, ethylbenzene, and xylenes (BTEX). BTEX compounds were not detected in any of these samples.

                        7. Samples of Williams Fork Formation production gas were collected from the Boulton 33-2 and Boulton 33-7 wells on July 20, 2004, from the Boulton 33-9 well on May 21, 2001 and September 9, 2004, and from the Boulton 33-8 well on October 17, 2005. Multiple bradenhead gas samples have been collected from all four wells on the G33 pad at various times between May 2001 and December 2005. The results of the stable isotope and compositional analyses of samples from the Water Well do not match the results of the gas samples from the wells on the G-33 pad because of bacterial degradation but are similar to the results of the gas samples from gas wells in the area (wells on the G-33 pad, P-3 pad and the Schwartz 2-15B well). EnCana’s experts note that gas composition from the Water Well samples was also similar to that sampled in shallow Wasatch Formation gases collected from the Moore 33-10A and 33-8A wells described in Finding 8, below.

                        8. On May 17, 2001 COGCC staff observed that the bradenhead pressures at the Boulton 33-9 and Boulton 33-8 Wells were 425 pounds per square inch gage (psig) and 300 psig, resulting in pressure gradients of 0.73 psi/ft and 0.50 psi/ft at the surface casing shoes, respectively. Ballard had previously remedially cemented the Boulton 33-7 on March 14, 2001, and tThe bradenhead on the Boulton 33-7 was inaccessible at that time. Ballard remedially cemented the Boulton 33-9 well on May 24, 2001. Also on May 24, 2001, Ballard remedially cemented the Boulton 33-8 at 2,401 feet to provide further zonal isolation for a Wasatch test conducted in June 2001. On December 15, 2004, EnCana observed bradenhead pressure of 170 psi/ft at the Boulton 33-7 and attempted three remedial squeezes in December 2004, January 2005, and June 2005. COGCC staff believes that elevated bradenhead pressures led either to the failure of the Wasatch Formation below the surface casing shoe or matrix cross flow in one or more of the wells on the G33 pad, and that Williams Fork Formation gas or gas from the deeper portion of the Wasatch Formation thereby migrated into the Water Well, which is 225 feet deep and completed in the shallow Wasatch Formation. EnCana’s engineers and consultants believe, based on extensive testing, that the gas in the Water Well more likely comes from gas that occurs naturally in the Wasatch Formation. In June 2001, Calpine Natural Gas Company drilled its Federal 14-33 well in the SE/4 of Section 33, less than half a mile from the Water Well. The 14-33 well encountered 20 gas shows above the top of gas during drilling, including numerous shows in the Wasatch formation. In 2004, EnCana drilled the Moore 33-10A to a depth of 1,200 feet; the well was drilled solely for the purpose of gathering data regarding the presence of shallow gas in the area because bubbles had been observed while drilling the Moore 33-8A surface casing interval to a depth of 1,236 feet. Operations were shut down on the Moore 33-8A to enable EnCana to gather data on the Moore 33-10A. EnCana performed extensive testing on the Moore 33-10A well, including obtaining and analyzing core samples.

                        9. As mentioned in Finding 6, BTEX compounds have not been detected in any of the samples collected from the Water Well samples. Dr. Anthony Gorody, an expert in geochemistry and gas seeps, on behalf of EnCana, evaluated the analytical results from samples collected during the investigation of this matter. Dr. Gorody concludes in his report dated March 18, 2005 that the absence of BTEX compounds in the water samples collected from the Water Well proves that there never was a direct, pressurized gas connection between potential gas sources on the G33 pad and the Water Well. COGCC staff does agree that BTEX compounds have not been detected in the Water Well; however based upon experience gained in responding to water well complaints throughout Colorado, COGCC staff does not agree with Dr. Gorody’s conclusion that there was not a direct, pressurized gas connection between potential gas sources on the G33 pad and the Water Well. Dr. Gorody also notes that the composition of the freshest, least-altered dissolved hydrocarbons in water from the Water Well is unique and cannot be matched to the composition of any other gas samples in the area. Mr. Mark Beeunas, an expert in stable isotope geochemistry, on behalf of the COGCC staff, also evaluated the analytical results from samples collected during the investigation of this matter. Mr. Beeunas concludes in his report dated October 14, 2005 that the thermogenic gas in the Water Well has been degraded by microbes, and, therefore, it is not possible to match thermogenic gas to its specific source gas. However, based upon analysis of a large body of data obtained by COGCC and operators from water wells in the area, gas in water wells in the area (other than the Water Well and the former Dietrich water well located in the SE¼ SE¼ of Section 3, Township 7 South, Range 92 West, 6^th P.M.) is biogenic and not thermogenic. In contrast, gas in the Water Well (and the former Dietrich water well) is thermogenic. In addition, the gas in most water wells in the area (other than the Water Well and the former Dietrich water well) is dry (composed of methane and ethane only) whereas the gas in the Water Well (and the former Dietrich water well) is wet (a mixture of methane, ethane, propane, n-butane, iso-butane, n-pentane, iso-pentane, and hexanes).

                        10. Thermogenic methane and other thermogenic gas constituents including ethane, propane, n-butane, iso-butane, n-pentane, iso-pentane, and hexanes have been detected in the Water Well, as described in Finding 5, but gas composition and stable isotope data from those dissolved gas samples collected at the Water Well, according to EnCana, suggest that new gas has not entered the Water Well since thermogenic gas was first detected in 2001. As interpreted by Dr. Gorody, on behalf of EnCana, water quality analyses from samples collected in the Water Well since gas was first detected in 2001 demonstrate that methane concentrations varied with time because of mixing between deeper aquifer fluids containing methane and shallower aquifer fluids devoid of methane.

                        11. COGCC staff have reviewed all well files, completion reports, fracturing records, field tickets, and analytical results from gas and water samples for all work done on the G33 pad wells from April 2001 to the present. The evaluation was designed to look for evidence of damage caused by fracturing and completing those wells. A review of all pressure records collected during frac operations indicate the stimulations were confined to the intended formation interval. None of the stimulation records exhibited severe pressure losses that would have occurred if the stimulation communicated with shallower formations including the aquifers of the Wasatch Formation. Analytical results from extensive water sampling of nearby water wells likewise demonstrate that no frac fluids were ever found to be present in the ground water. Fracture fluids used to stimulate wells on the G-33 pads were made up with 2%-4% potassium chloride, and the foam fracs used in the upper portion of the holes were made up of high concentrations of nitrogen. Therefore, if frac fluids had entered the Water Well, elevated levels of potassium or chlorides, would be expected to be detected in water samples, or nitrogen would be expected to be detected in gas samples. The absence of any detection of elevated levels of potassium, chlorides or nitrogen in any sample from the Water Well demonstrates that frac fluids have not reached the Water Well. As a result, it is reasonable to assume that if the fracture fluids were not detected in the Water Well, then additives to the frac fluids would also not have reached the Water Well. The test analyses indicate that ground water contamination at the Water Well is limited to dissolved methane and its associated thermogenic gas phase constituents. To date, BTEX compounds have not been detected in the Water Well; however, testing for these compounds will continue to ensure detection should they appear in the future. The impact to the Water Well is not a result of the hydraulic fracturing. According to the COGCC staff, the most likely cause of the gas impact in the Water Well is inadequate isolation of the Williams Fork Formation or the lower Wasatch Formation that resulted in the higher than normal bradenhead pressures and gas migration into the shallow Wasatch Formation.

                        12. On January 14, 2004, COGCC staff received a second complaint from Mr. Amos regarding lack of water supply from the Water Well. Staff notified EnCana of the complaint, and a week later EnCana’s contractor Cordilleran Compliance Services, Inc. ("Cordilleran") performed an extensive evaluation of the Water Well, including tests of the pump function, collecting water samples, slug tests to determine permeability and yield of the aquifer, and other analyses. Cordilleran also replaced the existing, non-functioning pump with a new pump, installed a 5,000-gallon vented cistern/storage tank for use by the households receiving water from the Water Well, installed additional electric power for the pump and cistern, performed additional chemical maintenance of the well, and repaired a significant leak in the water line leading to the Amos residence. Cordilleran also collected samples from the Water Well, which indicated 13 mg/l of methane but BTEX compounds were not detected; however, thermogenic methane, ethane, propane, n-butane, iso-butane, n-pentane, iso-pentane, and hexanes were detected. Additional samples from the Water Well were analyzed by Dr. Gorody on behalf of EnCana. Dr. Gorody’s interpretation was that the dissolved gas in the Water Well still maintained a thermogenic signature, but was strongly altered by methane-oxidizing bacteria. This made it even more difficult to identify a potential gas source.

                        13. Because bradenhead pressures on the G33 pad are relatively low and blow down completely within a few minutes, COGCC staff has not required additional remedial cementing but does require EnCana to continue monitoring the bradenhead pressures. EnCana continues to monitor bradenhead pressures of the wells on the G33 pad and vent them periodically. EnCana

reported measuring bradenhead pressures of the original four wells on the G33 pad between 130 and 140 psig during both the spring and fall of 2005.

                        14. On June 7, 2004, COGCC staff issued a Notice of Alleged Violation ("NOAV") to EnCana for impacts to the Water Well. The NOAV alleged violations of Rule 209.; Rule 324.A.a.; and Rule 906.a. The abatement required the operator to investigate the releases in accordance with Rules 909.a., b., and c., and remediate in accordance with Rules 910.a. and b. which required the sampling of the water well and submittal of a Site Investigation Remediation Workplan, Form 27, or other response by EnCana.

                        15. On July 23, 2004, COGCC staff received EnCana’s Site Investigation Remediation Workplan, Form 27, as required in the NOAV issued June 7, 2004. On July 26, 2004, COGCC staff sent a letter of approval with conditions to EnCana for its Site Investigation Remediation Workplan, Form 27. Copies of the approval letter and Form 27 were also sent to the Amoses and Walkers. The conditions of approval included collecting two (2) water samples on a quarterly basis; one sample directly from the water well prior to the discharge of the water into the cistern and one sample from a household water tap. Field parameters were to be measured and observations made during the sampling, including water color, odor, temperature, presence of bubbling, well flow rate, changes in water well performance during sampling, and well maintenance. The samples were to be analyzed for BTEX compounds, dissolved methane, total metals, major anions, bromide, nitrate and nitrite as total nitrogen, total dissolved solids, pH, and conductivity. In addition, on a semi-annual basis samples were to be collected directly from the water well prior to water discharge into the cistern for stable isotope and gas composition analysis.

                        16. Also on July 26, 2004, Dr. Gorody submitted a report to the COGCC, which concluded that the composition of dissolved methane in samples from the Water Well was thermogenic but bacterially altered and did not match either production gas from the Boulton 33-9 or bradenhead gas from the Boulton 33-2.

                        17. Results of compositional and stable isotopic analysis indicate residual gas in and around the Water Well continues to lose its identity due to the action of hydrocarbon-oxidizing bacteria. The contaminant is being attenuated naturally. EnCana is supplying potable water to the households using the Water Well.

                        18. Staff believes the fact that contents of separate gas-bearing strata and water-bearing strata were allowed to intermingle constitutes a violation of Rule 209. from January 14, 2004 through March 25, 2004. Staff also believes that EnCana failed to prevent an unauthorized discharge of gas in violation of Rule 324.A.a from January 14, 2004 through March 25, 2004. EnCana contests the violations, but to avoid an extended and contested hearing in this matter, has agreed to pay the fine set forth in Finding 20 below, and to continue the remedial action set out in Findings 21 and 22.

                        19. Rule 523. specifies a base fine of One Thousand dollars ($1,000) each day for each violation of Rules 209. and 324.A.a. The alleged violation of these two (2) rules occurred from January 14, 2004 through March 25, 2004 for a total of seventy-one (71) days. The total base fine in accordance with Rule 523.a. is One Hundred Forty Two Thousand dollars ($142,000). In accordance with Rule 523.d. the total fine should be reduced by 30% because of mitigating factors resulting in a recommended fine of Ninety-Nine Thousand Four Hundred Dollars ($99,400). The mitigating factors in determining this fine are as follows: (1) operator assisted impacted parties, (2) operator cooperated with the Commission with respect to the violation, and (3) correcting the violation reduced or eliminated any economic benefit to operator.

                        20. Rule 523.a. specifies that "no fine for any single violation shall exceed One Thousand Dollars ($1,000) per day" and that the maximum penalty for any single violation shall not exceed Ten Thousand Dollars ($10,000) in the absence of findings of significant waste, damage to correlative rights, or significant adverse impacts to public health, safety or welfare. EnCana does not admit liability for causing significant waste, damage to correlative rights or significant adverse impacts to public health, safety or welfare. However, it agrees to pay a total fine of Ninety-Nine Thousand Four Hundred Dollars ($99,400) in order to resolve this matter without the necessity of an extended contested hearing. A monetary penalty of Ninety-Nine Thousand Four Hundred Dollars ($99,400) should be assessed against EnCana for the above-described violations.

                        21. EnCana should continue to monitor the Water Well according to the approved Site Investigation Remediation Workplan, Form 27, until dissolved methane, ethane, propane, n-butane, iso-butane, n-pentane, iso-pentane, and hexane have returned to baseline levels for a sufficient period of time to insure any source within EnCana’s control has been eliminated.

                        22. EnCana should provide the households that use the Water Well with domestic and drinking water that meet Colorado drinking water quality standards and is free from methane, ethane, propane, n-butane, iso-butane, n-pentane, iso-pentane, and hexane.

                        NOW, THEREFORE IT IS ORDERED, that EnCana Oil & Gas (USA) Inc. shall be found in violation of Rule 209., failure to prevent the intermingling of the gas and water strata.

                        IT IS FURTHER ORDERED, that EnCana shall be found in violation of Rule 324.A.a., failure to prevent the unauthorized discharge of gas.

                        IT IS FURTHER ORDERED, that EnCana Oil & Gas (USA) Inc. shall be assessed a total fine of Ninety-Nine Thousand Four Hundred Dollars ($99,400) for the above-described rule violations, payable within thirty (30) days of the date the order is entered by the Commission.

                        IT IS FURTHER ORDERED, that EnCana shall provide the households that use the Water Well with domestic and drinking water that meet Colorado drinking water quality standards and is free from methane, ethane, propane, n-butane, iso-butane, n-pentane, iso-pentane, and hexanes.

                        IT IS FURTHER ORDERED, that COGCC staff may, in its sole discretion, approve a public project proposed by Garfield County in lieu of fine within thirty (30) days of the date this order is entered by the Commission.

                        IT IS FURTHER ORDERED, that if, prior to completing the obligations under this order, EnCana sells the Water Well or the property on which it is located to a third party, EnCana shall remain responsible for complying with this Order.

                        IT IS FURTHER ORDERED, that EnCana shall record a memorandum in the real property records of Garfield County giving public notice of the applicability of this order to the land on which the Water Well is located.

                        IT IS FURTHER ORDERED, that the provisions contained in the above order shall become effective forthwith.

                        IT IS FURTHER ORDERED, that the Commission expressly reserves its right, after notice and hearing, to alter, amend or repeal any and/or all of the above orders.

                        IT IS FURTHER ORDERED, that under the State Administrative Procedure Act the Commission considers this order to be final agency action for purposes of judicial review within thirty (30) days after the date this order is mailed by the Commission.

                        IT IS FURTHER ORDERED, that an application for reconsideration by the Commission of this order is not required prior to the filing for judicial review.

                        Recommended this ________ day of March, 2006.

                                                                            OIL AND GAS CONSERVATION COMMISSION

                                                                            OF THE STATE OF COLORADO

                                                                            By ________________________________________

                                                                                                            Brian Macke, Director

Dated at Suite 801

1120 Lincoln St.

Denver, Colorado 80203

AGREED TO AND ACCEPTED THIS _________ DAY OF MARCH, 2006.

ENCANA OIL & GAS (USA) INC.

By_____________________________

Joel S. Fox, Attorney-in-Fact