Wet Gas Gathering Pipeline Failure – Internal Corrosion Application of Root-Cause Analysis to Determine Cause(s) Quick-and-Easy Template

Root Cause Event Tree - Wet-Gas Gathering SITUATION Wet sour-gas gathering pipeline leak internal corrosion Failure at 9-months after start-up 10-times faster than maximum calculated corrosion rate (deWaard & Milliams) Actual corrosion distribution pattern different than predicted Internal corrosion damage limited to initial 100 metres of pipeline No corrosion defects after 100 metres (2.5 km of pipeline with no defects) Corrosion expected to be distributed within isolated regions along pipeline where stagnant water trap can form, and subsequent reduction of local pH EVIDENCE UWI Severity Score 0.98 (max 1.0) Aggressive pitting along pipeline for initial 100 metres Pitting along entire length of damaged pipe Pigging pattern is not expected distribution Pitting rate is 10-times higher than maximum calculated corrosion rate

Root Cause Event Tree - Wet-Gas Gathering Conclusions from Root-Cause Investigation SUSCEPTIBLE MATERIAL ACTUAL CORROSIVE CONDITION NOT PROPERLY CHARACTERIZED Detrimental fluid flow Corrosive material remained stagnant in the pipeline Corrosive fluids accelerated corrosion rate Actual corrosion rate 10-times anticipated Highly corrosive fluids entered the pipeline at well-start-up UWI Severity Index for the well is within top 98 percentile in AB CORROSION NOT DETECTED PRIOR TO FAILURE Monitoring & Inspection Plan did Not Detect Corrosion Activity Prior to Leak MITIGATION PROGRAM NOT EFFECTIVE FOR THE CONDITIONS Mitigation standards not effective Mitigation application not effective

Wet-Gas Gathering Pipeline Leak Root Cause Event Tree - Wet-Gas Gathering EVENT = Wet-Gas Gathering Pipeline Leak OR Thermal Stress Corrosion 3rd Party Damage Weld Failure Construction Operator Error Other OR Internal External Third Party Assessment Confirms Internal Corrosion Additional Information Required No Data to Support TO PAGE 2 Evidence PAGE 1

Corrosion Not Detected FROM PAGE 1 Root Cause Event Tree - Wet-Gas Gathering Corrosion - Internal AND (All Conditions Must Exist for Leak to Occur) Susceptible Material Corrosive Fluids Detrimental Flow Active Corrosion Corrosion Not Detected TO PAGE 3 TO PAGE 4 TO PAGE 5 Monitoring & Inspection Plan did Not Detect Corrosion Activity Prior to Leak Bare Carbon Steel Construction Material Direct Contributor No Data to Support Evidence PAGE 2

Root Cause Event Tree - Wet-Gas Gathering FROM PAGE 2 Corrosive Fluids OR Produced Water from Upstream Production Source(s) Glycol / Water Carry-Over from Upstream Processing Facility AND CO2 Partial Pressure = 96 kPa H2S Partial Pressure = 542 kPa Temperature = 22 C Chloride = 90,000 mg/l Not applicable – source of production into the pipeline is from primary producing well with single UWI 00/13-16-116-06 W6M deWaard & Milliams Indicates Maximum Unmitigated CO2 Pitting Rate @ 8 years and an adjusted Pigging Rate @ 16 years attributed to formation of protective iron sulphide Direct Contributor Additional Information Required Evidence PAGE 3

Root Cause Event Tree - Wet-Gas Gathering FROM PAGE 2 Detrimental Flow Observation of pitting within initial 100 m of pipeline suggests accumulation of detrimental fluids / solids on the bottom-of-pipeline. Pitting pattern suggests direct contact of the bottom-of-pipeline with highly corrosive fluids occurred – protective iron sulphide scale is not intact, was not permitted to be repaired, and Pitting rate penetrated the pipeline within 9-months of operations vs expected 8 years (or 16 years with consideration of beneficial iron sulphide scale). Actual corrosion rate is 10-times predicted CO2 corrosion rate and 20-times predicted corrosion rate with adjustment for H2S:CO2 protective scale. Direct Contributor Evidence PAGE 4

Root Cause Event Tree - Wet-Gas Gathering FROM PAGE 2 Root Cause Event Tree - Wet-Gas Gathering Active Corrosion OR Corrosion at Expected Corrosion Rate Corrosion at Elevated Corrosion Rate AND Protective Film Does not Exist A Corrosion Rate Accelerator is Introduced OR OR Oxygen Bacteria Detrimental Well Fluids Ineffective Mitigation Non-Protective Scale OR No Inhibitor Inappropriate Inhibitor Ineffective Inhibitor Standards Corrosion pitting morphology is consistent with ingress of detrimental fluids from upstream well. Upstream UWI score is within the top 0.99 percentile of 350,00 UWI events with respect to expected contribution to internal corrosion of downstream pipelines. Continuous inhibitor, batch inhibitor, routine pigging performed Batch inhibitor application method and/or frequency not sufficient to avoid pitting initiation Batch inhibitor application not sufficient to stop growth of active corrosion TO PAGE 6 PAGE 5

Environment Promotes Protective Scale FROM PAGE 5 Root Cause Event Tree - Wet-Gas Gathering Non-Protective Scale OR Environment Promotes Protective Scale Inappropriate Environment for Scale Formation AND Scale was Disrupted Scale was not Allowed to Repair OR Actual observation of pitting pattern confirms repair of disrupted iron sulphide film did not occur. High chloride levels competed with inhibitor within active pits preventing self-repair Chemical Mechanical Acid Jobs Dry Pigging Inspection Tools Improper Suspension Detrimental Flow Conditions & Settling of Solids Polysulphides Direct Contributor No Data to Support Pitting location and morphology suggests the culprit fluids were not produced during steady-state operation, otherwise they would not impact the pipeline. The propensity of the pigging towards the initial 100 metres of pipeline length suggests highly corrosive material were deposited into the pipeline during non-steady-state well operation, and it is likely these fluids were extremely low pH based upon the pitting pattern, and high-rate pitting attack rate. UWI performance score supports extreme likelihood of harming downstream pipelines. Evidence PAGE 6