DEEP PANUKE TECHNICAL NOTE

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1 DEEP PANUKE Page 1 of 33 TECHNICAL NOTE Topic: Removal of Beach Valve Station Isolation Valve Assembly (P74-SDV-011) Assessment Background: The Deep Panuke gas export pipeline is approximately 175km in length and comprised of an offshore and onshore section. The offshore and onshore pipeline sections are approximately 172.3km and 2.7km in length respectively. The onshore pipeline is located from landfall to the interconnection with the Maritimes and Northeast Pipeline (M&NP). The pipeline has two onshore facilities referred to as the Beach Valve Station (BVS) and Gas Export Pipeline Terminus (GEPT). The BVS is located at landfall and contains a valve (i.e. P74- SDV-011), which can be opened or closed either remotely via the PFC or locally by an individual on site. The GEPT is located adjacent to the M&NP facility and contains a pig receiver and a valve (i.e. P74-SDV-021) which can be opened or closed either remotely via the PFC or locally by an individual on site. The valves are opened or closed via a gas over hydraulics actuator. Details of the onshore pipeline and facilities are located in document DMEN-O22-PD-PR P&ID Onshore Pipeline, Beach Valve Station and GEP Terminus which is located in Appendix A. A plan view of the onshore facilities and pipeline right of way locations is located in Appendix B. An isometric view of the beach valve station assembly above and below grade piping is located in Appendix C. On April 23, 2014, an in-line inspection tool was launched from the offshore Production Field Center (PFC) with an expected arrival at the gas export pipeline 02U 18-Jun-14 Issued for Use D. Trask K. Tonn H. Farrell K. Tonn 01R 16-Jun-14 Issued for Review D. Trask K. Tonn H. Farrell K. Tonn Rev. Date Reason for Issue Prepared Checked Approved Approved Title: Removal of Beach Valve Station Isolation Valve Assembly (P74-SDV-011) Assessment DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penal provisions of the law.

2 DEEP PANUKE Page 2 of 33 terminus onshore receiver of April 24, At approximately 10:45 am on April 24, 2014, the inline inspection tool arrived at the beach valve station; however, the tool did not arrive at the onshore receiver and was subsequently confirmed to have stopped at the beach valve assembly. The approximate tool location was determined to be upstream of the first 6-inch tee based upon the receiving the 22Hz transmitter signal from the Wavetrack device located on the inline inspection tool. On June 11, 2014, digital radiography was performed on the excavated pipe section which has confirmed that the inline inspection tool is located upstream of the first 6-inch tee as illustrated in Appendix D. Discussion Inspection Tool Removal Plan Encana has now concluded that it is highly unlikely that the in-line inspection tool will become dislodged on its own and is now planning to remove the in-line inspection tool by performing on-line isolation and cut-out. The proposed removal plan involves performing line isolation both upstream and downstream of the beach valve assembly, removing the beach valve assembly (complete with in-line inspection tool) and re-installing a straight section of linepipe. The planned steps include the following: Weld on split tee fittings (both upstream and downstream of beach valve assembly) rated to the approved pipeline maximum operating pressure (MOP) Weld on purge and equalization fittings Perform hot tap through fittings Insert double isolation (ie. T.D. Williamson - Stopple Train) both upstream and downstream of the beach valve assembly Depressurize and gas free isolated section Cut and remove the beach valve assembly which includes from a location upstream of the inline inspection tool and downstream of the second 6- inch tee as illustrated in Appendix E. Install new straight section of linepipe and oxygen free Remove isolations (i.e. TDW Stopple Train) Install completion plugs and blind flange assembly on hot tap locations The target date for the removal of the beach valve assembly (complete with inline inspection tool) is September Once removed, surplus certified linepipe will be used to reinstate the gas export pipeline. DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

3 DEEP PANUKE Page 3 of 33 Due to required procurement lead times, new valve and extruded headers (tee section) would be unable to be procured in time to re-install in the line during the anticipated September 2014 line isolation program. Since the Deep Panuke gas export pipeline is currently considered Class 1 in accordance with CSA Z662-11, the isolation valve at the beach valve station is not required. A detailed discussion on the requirement of the beach isolation valve is contained in the next section. In the event that future development adjacent to the onshore pipeline occurs, which requires the class of pipeline to be changed to Class 2, the isolation valve will be reinstated with a similar line isolation methodology. The line isolation would not require a new hot tap but rather a re-entry would be performed via the existing hot tap locations. Discussion Requirement for Beach Isolation Valve (P74-SDV-011) The onshore pipeline is located within an industrial park and CSA Z662 (Section 4.3.3, Table 4.1, Note 2) requires that If it is likely that there will be future development in the class location assessment area sufficient to increase the class location designation, consideration shall be given to designing, pressure testing, operating, and maintaining the pipeline in accordance with the requirements applicable to the higher class location. During the design phase of the onshore pipeline, both a petrochemical and a LNG import terminal were proposed to be located adjacent to the onshore pipeline route by Keltic Petrochemical and Maple LNG. As a result, if these developments were built, the Deep Panuke pipeline would be a Class 2 designation. Thus as these proposed developments were under consideration at the time of the development application and possibly could be approved, it was decided to design the onshore pipeline for Class 2 requirements. This would require a maximum valve spacing of 25km for the onshore pipeline section in accordance with Table 4.7. As a result, valve P74-SDV-011 was installed at the landfall location on the assumption that these projects would proceed. Subsequent to the onshore pipeline design phase, both the Keltic Petrochemical and Maple LNG import facility projects have been cancelled and no development has occurred. As a result, the Deep Panuke pipeline is currently Class 1 in accordance with CSA Z662-11, and the isolation valve at the beach valve station is not required as described in the following sections. DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

4 DEEP PANUKE Page 4 of 33 Regulatory Requirement: The onshore pipeline section is regulated by the National Energy Board (NEB) in accordance with the Onshore Pipeline Regulations. The Onshore Pipeline Regulations (OPR) have no specified requirement for valve locations and spacing; however, Section 4(1) states that the pipeline is required to be designed, constructed, operated or abandoned in accordance with CSA Z662. Section 42 of the NEB Onshore Pipeline Regulations state: If the class location of a section of a pipeline changes to a higher designation that has a more stringent location factor, the company shall, within six months after the change, submit the proposed plan to deal with the change to the Board. (See Appendix F for OPR Section 4(1) and 42). In addition, a variance of Certificate GC-111 in accordance with Section 21 of the NEB Act is required in order to remove this valve. CSA Z662 Requirement: The Deep Panuke onshore pipeline has been designed, constructed and installed in accordance with CSA Z662 as per the OPR. Section 4.4 of CSA Z662 (See Appendix G) provides requirements for isolation valve location and spacing and states that Isolating valves shall be installed for the purpose of isolating the pipeline for maintenance and for response to operating emergencies. The number and spacing of these valves must comply with Table 4.7 or otherwise can be determined by an engineering assessment. Table 4.7 specifies the maximum valve spacing based upon the type of pipeline and class location. The class location is specified in Section 4.3.2; in particular, Table 4.1. The current type of pipeline and Class location for Deep Panuke is as follows: Type of Pipeline = Gas Class Location Designation = Class 1 DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

5 DEEP PANUKE Page 5 of 33 Note: The basis for Class 1 is that currently no dwellings, building, outside occupied areas or industrial installation are located along the onshore pipeline route. The onshore pipeline is located within an industrial park and the only nearby structures present are three (3) wind turbines for which with no persons are present during normal use. Thus in accordance with Table 4.7, for a gas pipeline with Class 1 designation, there is no code requirement with regards to isolation valve locations and spacing based upon the current development status near the onshore pipeline route. Safety Considerations: Encana has requested that PSRM Services perform a technical review of the Onshore Safety Concept Analysis and other relevant project documentation to determine the potential impact to the Project Target Levels of Safety (TLS) from continued operations based upon current land use in the Goldboro area on the basis that the beach isolation valve (P74-SDV-011) is removed. The review concluded that the project remains within acceptable limits for the Deep Panuke Target Level of Safety, applicable land use risk acceptability criteria for Goldboro and the industry accepted ALARP range; therefore, no risk reduction recommendations have been deemed necessary. This technical review is located in Appendix H. Discussion Future Requirement for Isolation Valve (P74-SDV-011) Since the onshore pipeline is located in an industrial park, there is a potential for a change to Class 2 if an industrial installation or building occupied by 20 or more persons during normal use is situated next to the onshore pipeline as per CSA Z662 Table 4.1. Currently, an LNG import terminal is being proposed for the Goldboro industrial park with the earliest in-service date of In the event that the LNG export facility (or any other future facilities) are approved for construction and is situated next to the onshore pipeline such that it would increase the class location designation, then the beach isolation valve will be necessary. The existing isolation valve assembly will be reinstated, with a similar line isolation methodology. The line isolation would not require a new hot tap but rather a reentry via the existing hot tap locations. DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

6 DEEP PANUKE Page 6 of 33 Encana will continue to monitor future developments in the industrial park to determine if they will result in a class location designation change. In the event that a change occurs and a beach isolation valve is required, the required components will be procured and installed. Conclusions and Recommendations The Deep Panuke gas export pipeline is currently considered as Class 1 in accordance with CSA Z662-11, and thus no beach isolation valve is required. In addition, a technical review of the onshore Concept Safety Analysis was performed and concluded that Deep Panuke remains within acceptable limits for the Target Levels of Safety if the beach isolation valve is removed. As a result, the plan to remove the beach isolation valve assembly (complete with inline inspection tool) and replace with an existing certified linepipe section is considered acceptable. However, a variance of Certificate GC-111 in accordance with Section 21 of the NEB Act is required in order to remove this valve. Encana will continue to monitor the future developments in the industrial park to determine if they will result in a class location designation change. In the event that a class location change occurs and a beach isolation valve is required, the required components will be procured and installed. The isolation valve assembly would be reinstated with a similar line isolation methodology. The line isolation would not require a new hot tap but rather a re-entry via the existing hot tap locations. DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

7 DEEP PANUKE Page 7 of 33 Appendix A Onshore Pipeline, Beach Valve Station and GEP Terminus P&ID DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

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9 DEEP PANUKE Page 9 of 33 Appendix B Onshore Pipeline and Facilities Overview DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

10 Page 10 of 33 M&NP METERING FACILITY Encana GAS EXPORT PIPELINE TERMINUS FACILITY SOEP GAS PLANT WINDFARM INDUSTRIAL PARK BOUNDARY GOLDBORO INDUSTRIAL PARK Betty s Cove Brook DEEP PANUKE ONSHORE PIPELINE R.O.W. EXXON MOBILE ONSHORE PIPELINE R.O.W. BEACH VALVE STATION

11 DEEP PANUKE Page 11 of 33 Appendix C Beach Valve Assembly Isometric DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

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13 DEEP PANUKE Page 13 of 33 Appendix D Location of In-Line Inspection Tool DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

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15 DEEP PANUKE Page 15 of 33 Appendix E Beach Valve Assembly Cut Locations DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

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17 DEEP PANUKE Page 17 of 33 Appendix F OPR Section 4(1) and 42 DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

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21 DEEP PANUKE Page 21 of 33 Appendix G CSA Z Isolation Valve Spacing Requirements DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

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26 DEEP PANUKE Page 26 of 33 Appendix H Technical Review of Onshore Concept Safety Analysis DM EN O22 TN PL U Project Originator Location Type Disc. System No. Rev. This document is the property of EnCana Corporation who will safeguard its rights according to the civil and penalty provisions of the law.

27 PSRMServices Page 27 of 33 Technical Review of the Onshore Concept Safety Analysis Removal of Beach Valve Station Isolation Valve Assembly (P74 SDV 011) The below text provides the technical review and support, for the continued operation of the onshore Deep Panuke facility with the removal of beach valve P74 SDV 011. The below review confirms that the Deep Panuke onshore facility will remain within both the Project Target Levels of Safety and the applicable land use risk acceptability criteria for Goldboro and the industry accepted ALARP range if the beach valve is removed and that no risk reduction recommendations have been deemed necessary. A previous technical review was conducted to confirm that the Deep Panuke facility could operate safely without a functioning beach valve; that review confirmed that in effect the Projects Target Levels of Safety were not affected by the functionality of the valve given the occupancy of the surrounding areas. Introduction On April 23rd, 2014, an in line inspection tool was launched from the PFC and the expected arrival at the gas export pipeline terminus onshore receiver was April 24th, The tool did not arrive at the onshore receiver and was subsequently confirmed to have stopped at the beach valve assembly. Digital radiography was performed on the excavated pipe section which confirmed that the inline inspection tool was located just upstream of the first 6 tee. Previous problems with beach valve P74 SDV 011 had already prompted a review of the Deep Panuke onshore pipeline and functionality of the beach valve actuator and concluded that the function (and hence presence) of the valve did not affect the Project Target Levels of Safety. Further it has been proposed that since the Deep Panuke gas export pipeline is currently considered Class 1 in accordance with CSA Z662 11, the isolation valve at the beach valve station is not required per regulation. As the Class 1 designation is contingent on the absence of adjacent industry, it is acknowledged that in the event that future development adjacent to the onshore pipeline occurs which could result in a change in the class of the pipeline, the isolation valve could be reinstated with a similar line isolation methodology to the removal. From a safety perspective the prior review which considered the impact on the Project Target Levels of Safety from an inoperable beach valve P74 SDV 011 is very similar to the proposed removal case. As such, this review will look at the Concept Safety Analysis (DMAE X00 RP LC R completed by ESR Technology, July 2011) and other relevant project documentation to determine the potential impact to the Project Target Levels of Safety (TLS) from continued operation without the ability to isolate the gas export pipeline at the beach. The approach to this technical review is to take a high level look at the data (typical input parameters which ESR would have used in developing their QRA leak frequency, isolation, ignition frequency and type, population/occupancy, hazard range/effect, etc ) which form the basis for the individual risk for the onshore project to confirm the relative impact which would be seen from removing the isolation valve and associated assembly at the beach valve location. Note that within the current QRA (Concept Page 1 of 7

28 PSRMServices Page 28 of 33 Safety Analysis Section 5 QUANTITATIVE RISK ASSESSMENT OF ONSHORE RELEASES) there are numerous conservative assumptions which have now been eliminated (due to other adjacent projects being cancelled) and a factor of failure (9%) was already placed on this beach valve. The focus of this review will be the risk to personnel in line with the Concept Safety Analysis identified hazards and in accordance with the Project TLS and land use criteria. Note that the Concept Safety Analysis did look at environmental risk as well but during the hazard identification process no high risks to the environment were identified. Given the noted CSA evaluation of environmental risk and that this is a natural gas pipeline system with no liquids nor hazardous levels of H 2 S we have not considered environmental risk further in this review. Acceptance Criteria The Target Levels of Safety (TLS) for the Deep Panuke facilities are defined in the Design Memorandum, and are summarized in Table 1. No. Description Target Level of Safety (freq./year) 1 Individual Risk <1 x Group Risk (based on 68 POB) <1.36 x 10 3 ( 10 fatalities per year) <2.72 x 10 4 ( 50 fatalities per year) 3 Environmental Risk ALARP 4 Production Facility Impairment (includes TLS for PFC primary structure, TR impairment frequency, escape route and evacuation system) Table 1: Target Levels of Safety <1 x 10 3 Loss of integrity to the installation s key safety functions from all major accident events. <1 x 10 4 Loss of integrity to the installation s key safety functions from any single major accident events. The onshore facilities at Goldboro are also subject to the Major Industrial Accident Council of Canada risk acceptability criteria summarized below in Table 2. Intolerable Grey Insignificant Table 2: Land Use Criteria Individual Specific Risk (ISR) > 10 4 pa 10 6 < ISR < 10 4 pa < 10 6 pa Technical Sensitivity Review The approach taken in this review is to consider the key components which go into defining the Location Specific Individual Risk (LSIR) and Individual Risk (IR) values and for each one to consider whether the beach valve has any bearing on the assessment and if it does to determine to what extent its removal would affect the contributing risk value. Page 2 of 7

29 PSRMServices Page 29 of 33 The starting points are the hazard cases to be considered, these are defined within the CSA (see the below two bullets). Since the concentration of hydrogen sulphide in the export gas does not exceed 4ppm, the major hazards associated with releases from the onshore facilities were considered in the QRA as being: Immediate ignition leading to a jet fire Delayed ignition leading to either a flash fire or a vapour cloud explosion, burning back to a jet fire. Our focus is the risk to individuals; as such we are looking at the events which would lead to personnel being within the hazard envelope of a flash fire or jet fire heat flux with lethal doses (Note: vapor cloud explosion was considered in the original FEED QRA, this is discounted now and explained below). When considering the event potential from a QRA perspective we would have three starting cases. 1. Event failure (release frequency) with NO ignition. 2. Event failure (release frequency) with immediate ignition. 3. Event failure (release frequency) with delayed ignition. Note that the distance from surrounding facilities to the beach valve is not the main factor with regards to the risk contours. It is the leak source proximity to the SOEP Gas Plant and M&NP Metering Facility that dictates the risk contour arrangement. The leak source is considered as the base input to the QRA as being an assumed frequency per unit length for the pipeline section and based on part counts for the beach valve location and the Terminus (next to the M&NP Metering Facility). As such, worst case scenarios (rupture) have been assumed at all points along the onshore pipeline section from the beach valve to the Terminus. The greatest risk to the SOEP Gas Plant facility from the Gas Export Pipeline (GEP) system would come from the points closest to the SOEP, based on their assumed likelihood of failure with consequence radii that could impact the SOEP for small, large and rupture cases. This defines the location specific individual risk and the group risk would then need to account for likelihood of occupancy in that area reaching the levels required to exceed the set group risk criteria. The QRA risk contours are based on small, large and rupture case events. The risk contours take these entire event cases combined to form the individual risk contours provided within the CSA. If we were to focus on worst case alone, breaking out the individual risk contour for just the rupture case, this would mean we consider only a small portion of the contributing risk to personnel and the risk contour would reduce. For example, if we look at the risk contours corresponding to the individual risk considering just the worst case scenario (rupture), they do not cross the existing SOEP Gas Plant boundary at the levels dictated by our Target Levels of Safety for Individual Risk (<1 x 10 3), and will remain compliant with the Land Use Criteria of < 10 6 pa (per annum) for Individual Specific Risk. Group risk has not been considered in the original QRA and ESR CSA update as the pipeline and onshore facilities are not within a populated area and the onshore facilities are normally unmanned. Page 3 of 7

30 PSRMServices Page 30 of 33 As mentioned the area is predominantly unmanned and hence detection and action would normally rely on the pipeline leak detection system. The CSA assumed that the pipeline leak detection system was capable of detecting leaks of 2% normal steady flow and greater. Based on the pipeline leak detection system in place the design QRA also assumed that full ruptures would be detected in 5 minutes, 10% leaks in 10 minutes, 5% leaks in 25 minutes and 2% leaks in 50 minutes. As immediate ignition is assumed to occur within 5 minutes and all delayed ignition occurs after 5 minutes, and given that it is considered unlikely that any leak from our system would be detected within 5 minutes, it is assumed that all immediate ignition cases will occur before there would be any remote or manual attempt to close the beach valve if present. The isolated nature of the location and lack of human presence in the immediate surrounding areas further supports this assumption. As such, all immediate ignition cases will happen regardless of whether the beach valve is installed and functioning or not installed and therefore has no impact on whether the beach valve is provided or not. In support of the above statement, it has been considered that without isolation the inventory of the subsea pipeline is greater than the isolated onshore pipeline section and therefore the leak release conditions will decay much slower than a smaller isolated inventory. However, in our assessment we consider all factors of risk including likelihood which addresses the occupancy of the area and the reaction of personnel, not just the consequence envelope. Additionally for immediate ignition the impacted area will be at it s greatest with the highest pressure, at the start of the release. This is the same for both cases whether isolation is achieved or not in fact this is the same for a period of 5 minutes in the case of a full rupture which is the time considered by the QRA and CSA for action to be taken to remotely close the beach valve (10 minutes for leaks of 10% volume and 25 minutes for leaks of 5% volume). As we have immediate ignition we are dealing with jet fire cases only and as per the QRA and CSA all immediate ignition cases are assumed to occur within 5 minutes. As isolation was not considered by the QRA to occur within 5 minutes and considering that all immediate ignition cases occur within 5 minutes, the immediate event would be the same regardless of whether the beach valve is functional and present or not. The QRA and CSA assume that jet fire cases will result in 100% fatality at 37.5 kw/m2, 50% fatality at 25 kw/m2, 10% fatality at 12.5 kw/m2 and 1% fatality at 9.5 kw/m2. The only differences in consequence from having an isolating beach valve compared to no isolation are that the jet fire exposure area will not reduce as quickly. However, it is important to note that the consequence envelope will not increase, we do not consider that people will walk into the jet fire envelope, we have no temporary refuge buildings where we the jet fire could become an issue for trapped personnel, all areas provide relatively free access for escape of any individual that is in the area and not affected by the initial immediate ignition jet fire event. Also note that the QRA and CSA show that immediate ignition events dominate the risk accounting for 78% of the risk profile. As such and as noted the functionality of the beach valve therefore can only have an impact on the remaining 22% of the risk profile (discussed in the next few paragraphs). Following on from the above reasoning if there is no ignition, then there is no consequence and no risk. As such, the only cases where the function of the beach valve could have an impact on our risk levels are the delayed ignition events. Page 4 of 7

31 PSRMServices Page 31 of 33 Considering just the delayed ignition events it was already assumed that the beach valve would fail for 9% of demands. This means we are looking at the impact from changing the basis of this remaining 91% to reflect that the beach valve has been removed. Explosion events were considered in the FEED and design QRA, these were predominantly associated with the potential congestion of the Maple LNG Facility. As neither the Maple LNG Facility nor the Keltic Petrochemical Facility materialized, the explosion events associated with the locations have no relevance to the beach valve removal or not. The CSA did consider within the consequence section that there were potential noted congested areas within the SOEP Gas Plant. The area considered is located at 480 m from the gas export pipeline. The maximum LFL range considered was 550 m for LFL and 834 m for ½ LFL. The QRA considers that these levels are achieved at a leak flow rate of 5240 kg/s which is the maximum instantaneous rupture release case seen. This release rate decays rapidly and the predicted release rate after 2 minutes (un isolated as no isolation is assumed to occur before 5 minutes) would have dropped to 63 kg/s as referenced in the QRA. At this flow rate the release case produces a maximum LFL range of 78 m and a maximum ½ LFL range of 137 m. The CSA goes on to state in section that Since the initial rupture release rate of 5240 kg/s decays very rapidly and would lead to very pessimistic hazard ranges, it is more reasonable to use the average release rate over the first 2 minutes (879 kg/s in the case of ruptures) when assessing the immediate ignition jet fires, whether isolated or not. For the delayed ignition cases, the release rate will depend on whether or not the release is isolated. It is reasonable to consider delayed ignition as taking place after 5 minutes, corresponding to an isolated rupture release rate of 0.7 kg/s. Later ignition would result in even smaller isolated release rates. In the case of un isolated, delayed ignition rupture releases, we conservatively use the normal operational flow rate of 74 kg/s, although it is unlikely that normal flow rate could in reality be sustained following a rupture. For unisolated, delayed ignition large and small leaks, we use the release rate after 2 minutes, as compared to after 5 minutes for the isolated, delayed ignition leaks. Based on the above the CSA and the QRA did not consider the consequence envelope associated with the instantaneous release rate of 5240 kg/s due to the rapid decay and, we assume, inability to sustain the cloud volume. They considered instead a conservative basis for the consequence modelling input to the risk calculation of un isolated delayed ignition cases as being based on the continuous volumetric flow rate from the platform. This case would produce an LFL and ½ LFL radii similar to the 63 kg/s case previously noted and are well outside of the 480 m spacing between the GEP and the SOEP congested areas. As such the CSA and QRA did not consider within the risk calculations delayed ignition cases which could have reached the SOEP congested areas. Given that the Maple LNG Facility along with the Keltic Petrochemical Facility did not materialize and as the SOEP facility was considered within the QRA as having no potential for vapour cloud explosion (blast overpressure effects) there are no other congested areas left within the LFL range for the structures present today (tree s in the area are routinely cleared). This further reduces the events that could be affected by the beach valve removal. This also removes the vast majority of the risk associated with the pipeline failure cases and essentially all of the risks from the beach valve removal as the areas within the range of hazard envelopes predicted by the consequence modelling are now unmanned and restricted access. Page 5 of 7

32 PSRMServices Page 32 of 33 The main remaining difference is from an un isolated delayed ignition event around the SDV and pig receiver location where a failure to isolate the beach valve will result in a prolonged release rate higher than for the isolated case. Hence the hazard envelope will be slightly larger and when we consider the probability of being exposed to the hazard effect we have a slightly increased area to consider. Isolation Hole Category Hole Size (m) Release Rate at Ignition (kg/s) Isolated Small Un isolated Small Isolated Large Un isolated Large Isolated Rupture Un isolated Rupture Table 3: Onshore Export Pipeline Release Rates for Delayed Ignition Case Based on the above and the QRA assessment consequence data, jet fire hazard ranges to critical heat flux levels for flow rates of 0.7 kg/s and lower do not generate a lethal heat dose. As such isolation of the beach valve or no isolation of the beach valve will have no impact to the individual risk from small release cases and jet fire hazard events. The same applies to the LFL cases and flash fire events for small leaks. As small leak cases contribute 80% of the leak frequencies overall and 90% for the main SDV and pig receiver location this finding further reduces the impact that the beach valve has on the target levels of safety for the onshore facility. Additionally the hazard envelopes for the large hole categories that equate to the difference in release rate amount to an approximate 20% increase in hazard envelope size. To be conservative we have factored a 100% increase into our assessment over the contributing risk from the large cases. Given the significant difference between flow rates for the rupture case we have considered 100% fatality from the delayed ignition cases this area is the most noticeable impact from removal of the beach valve but contributes only a small amount to the overall risk for the facility. It should also be mentioned now that there are a very small percentage of leaks which would go undetected and still contribute to the hazard events which would determine the risk for the facility. For these undetected leaks the provision of a beach valve or not has no impact on the event outcomes (as with no detection there is no action to close the valve) and hence would not factor into this comparison. As mentioned above, now that the Maple LNG Facility along with the Keltic Petrochemical Facility have been cancelled the beach valve area and onshore piping section upto the SDV and pig receiver location adjacent to the M&NP Custody Transfer Station has effectively no normal personnel activity or presence and no public exposure (other than intruders for which signage has been posted). As such these two areas contribute very little to the overall individual risk for the Onshore facility which makes the main focus the SDV and pig receiver location where personnel attendance may be required and where the Terminus has its closest proximity to the adjacent M&NP custody transfer station. Further it should be considered that as a result of removing the beach valve and all associated instrument tubing we would be decreasing the overall risk associated with leak sources from that location. Page 6 of 7

33 PSRMServices Page 33 of 33 If we were to consider that 100% of all resultant delayed ignition events (based on the prior qualifications and discounted events) around the SDV and pig receiver location were to result in fatality, and ignore any potential risk reduction from removal of leak paths associate with the beach valve, we would pessimistically change the LSIR (Location Specific Individual Risk) from 6.1 X 10 6 per year to approximately 9 X 10 6 per year. This is an increase in overall location specific individual risk at this location of over 150% and contains a number of conservative assumptions. Such a conservative basis would result in an equivalent IR of 1.8 X 10 7 per year. This level of individual risk is still well below the widely accepted ALARP level of 1 X 10 6 per year and would be classified as insignificant in accordance with the Major Industrial Accident Council of Canada land use risk acceptability criteria. This level also falls well below the Encana Project Individual Risk (IR) Target Level of safety of <1 x This sensitivity study is based on very conservative assumptions; a more detailed assessment would further reduce the difference between the IR levels seen when comparing the effect of removing the beach valve from the gas export pipeline. This technical review indicates that the removal of the beach valve will not impact the Project Target Levels of Safety or the more stringent land use criteria. Yours Sincerely, Colin Sewell Managing Director 19 th June 2014 Page 7 of 7