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Home My WebLink About2024 CINGSA 3000 Spenard Road PO Box 190989 Anchorage, AK 99519-0989 May 15, 2025 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Attn: Jessie Chmielowski – Chair of Commission RE: Cook Inlet Natural Gas Storage Alaska Annual Material Balance and Storage Performance Report Dear Chairman Chmielowski: Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) was granted a Storage Injection Order on November 19, 2010 by the Alaska Oil and Gas Conservation Commission, allowing it to operate the Cannery Loop Sterling C Pool for underground natural gas storage service. Per CINGSA’s request, the Commission issued an amended Storage Injection Order (SIO) No. 9A, in 2014. Rule 8 of SIO 9A requires that CINGSA annually file with the Commission a report that includes material balance calculations of the gas production and injection volumes and a summary of well performance data to provide assurance of continued reservoir confinement of the gas storage volumes. Per Storage Injection Order No. 9.001, the Commission revised the due date for this Report to May 15 of each year. CINGSA has now completed thirteen full years of operation. The enclosed report, in compliance with Rule 8 of SIO 9A, documents gas storage operational activity during the past twelve years and includes monthly net injection/withdrawal volumes for the facility and total gas inventory at month-end. Any questions concerning the attached information may be directed to Richard Gentges at 989-464-3849. Sincerely, Matthew Federle Director Cook Inlet Natural Gas Storage Alaska, LLC Attachment Cook Inlet Natural Gas Storage Alaska, LLC 2025 Annual Material Balance Analysis Report To Alaska Oil and Gas Conservation Commission (AOGCC) May 15, 2025 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 2 Cook Inlet Natural Gas Storage Alaska, LLC 2024-2025 Storage Field Injection/Withdrawal Performance and Material Balance Report Executive Summary/Conclusion Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) filed an application with the Alaska Oil and Gas Conservation Commission (AOGCC) on July 27, 2010, for authority to operate the Cannery Loop Sterling C Pool to provide underground natural gas storage service. In that application, CINGSA requested the authority to store a total of 18 Bcf of natural gas, including 7 Bcf of base gas and 11 Bcf of working gas . CINGSA estimated that this initial phase of development would result in a maximum average reservoir pressure of approximately 1520 psia based upon the original material balance analysis of the reservoir, all as more fully described in the application. By Order dated November 19, 2010, AOGCC issued Injection Order No. 9 (SIO 9) granting CINGSA the authorization sought in its application and limiting the maximum allowed reservoir pressure to 1700 psia. On November 15, 2012, CINGSA filed an Application for Storage Capacity Certification (Form 10-427) with the AOGCC. CINGSA requested a capacity certification of 11 Bcf of working gas consistent with CINGSA’s contractual obligations to provide firm storage service under Firm Storage Service Agreements with its customers. On May 15, 2013, the Commission granted CINGSA’s certification but limited the certified amount to 10.5 Bcf. On June 4, 2013, CINGSA petitioned for reconsideration of this certification; this petition was denied by letter dated June 14, 2013. In April 2014, CINGSA subsequently applied to the AOGCC requesting authority to increase the maximum reservoir pressure to the original discovery pressure of 2200 psia . By Order dated June 4, 2014, the AOGCC issued Injection Order No. 9A, granting CINGSA the authorization sought in its April 2014 application. On August 15, 2022, CINGSA applied to the AOGCC to increase the storage capacity of the facility to 12.5 Bcf of working gas. The application included ten years of operating history which demonstrates the increase in capacity will not result in the reservoir exceeding the maximum reservoir pressure approved by the Commission in the Commission’s June 4, 2014, Injection Order 9A. The Commission administratively approved the requested increase in capacity on August 17, 2022. Lastly, in preparation for an expansion of the facility to provide both increased working gas capacity and increased maximum deliverability, CINGSA submitted a second Application for Storage Capacity Certification (Form 10-427) to the AOGCC on May 26, 2023. In this application CINGSA requested the authority to store a maximum of 13 Bcf CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 3 of working gas. CINGSA again supplied supporting data to demonstrate that the requested authorization would not result in the reservoir exceeding the maximum reservoir pressure approved by the Commission in the Commission’s June 4, 2014, Injection Order 9A. The Commission administratively approved the requested increase in capacity on July 13, 2023. Pursuant to SIOs 9 and 9A, An annual report evaluating the performance of the storage injection operation must be provided to the AOGCC no later than May 15. The report shall include material balance calculations of the gas production and injection volumes and a summary of well performance data to provide assurance of continued reservoir confinement of the gas storage volumes. This is the thirteenth such annual report to be filed by CINGSA. The CINGSA facility was commissioned in April 2012 and has now completed thirteen full years of operation. This report documents gas storage operational activity during the past twelve months and includes monthly net injection/withdrawal volumes for the facility and total inventory at month-end. A plot of the wellhead pressure versus total inventory of the field since commencing storage operations is contained in this report; the plot demonstrates that the pressure versus inventory performance is generally consistent with design expectations, although actual pressure has trended above design expectations. CINGSA believes the reason for this is related to an isolated pocket (separate reservoir) of native gas, believed to be at or near native pressure conditions, which CINGSA encountered when it perforated/completed the CLU S-1 well. This gas has since commingled with gas in the depleted main reservoir and provides pressure support to the storage operation. Based upon currently available data, the estimated volume of gas associated with the separate reservoir falls in the range from 14-24 Bcf. During the past twelve months CINGSA completed a major expansion of the facility to provide an additional 2 Bcf of storage capacity and increased deliverability. The expansion included two new injection/withdrawal wells, a second identical gas conditioning train, and two additional 2750 horsepower Ariel KBC compressors. These facilities were placed into service on 12/11/2024 and are now available to support CINGSA’s customers. The two new wells, CLU S-6 and CLU S-7, were drilled and completed along the central western flank and northeast region of the reservoir, respectively to improve drainage from these two areas. Neither well was available for service prior to the end of CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 4 the 2024-2025 withdrawal season. A more detailed discussion of each well is contained in the body of this report. This report also documents the injection/withdrawal flow rate performance of each well and test results where applicable. CINGSA conducted a back-pressure test on CLU S-1, CLU S-2, CLU S-3 and one of the new wells, CLU S-7 in March and April 2025. The results of each test are documented in the body of this report. CINGSA should continue to periodically back-pressure test all seven of its storage wells. A 2-3-year rotational basis should be adequate to confirm that all wells are performing consistently and with no loss of deliverability capability. An exception to this schedule should be considered which mandates testing after any significant workover activity (cleanouts, re-perforating, etc.) The test results may also provide an early indication of a loss of storage well integrity if a loss of integrity were to occur. At this time, there is no evidence of a decline in deliverability of any of the wells related to a loss of wellbore integrity. Consistent with standard operations and the general requirements outlined under the AOGCC’s SIO 9a, dated June 4, 2014, two planned facility shutdowns were conducted during the past twelve months, each approximately one week in duration. The first shutdown occurred during the period of September 9-16, 2024, and the second during the period of April 14-21 of this year. The purpose of these two shutdowns was to suspend injection/withdrawal operations so that each well could be shut-in for pressure monitoring and to allow reservoir pressure to begin to stabilize. The well shut-in pressure data was analyzed via graphical material balance analysis. The pressure versus inventory relationship of the field is consistent with historical performance and does not indicate any evidence of a loss of storage gas or reservoir integrity. These results support the conclusion that all the injected gas remains confined within the reservoir. The CINGSA facility operates with two custody transfer meters, one of which is connected to the “CINGSA lateral” and the other to the KNPL pipeline. Monthly calibration checks are performed on both meters to confirm they are performing within the manufacturer’s specifications. A loss of calibration could result in a measurement error impacting storage inventory and necessitate an adjustment to inventory. No adjustments to storage inventory were necessary during the period from May 1, 2024, through April 2025. Each well that penetrates the cap rock of the Sterling C Gas Storage Pool could be a leak path for injected storage gas. If a loss of wellbore integrity were to occur in a well that penetrates the storage formation, it could manifest itself via a rise in the annular pressure CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 5 of that well. Direct evidence of a loss of integrity could include, but may not be limited to, annulus pressure equal to the storage operating pressure and/or cyclic pressure behavior that matches that of the injection/withdrawal wells, or a loss of positive pressure on the inner-most annulus of CINGSA’s storage wells (a requirement of AOGCC unique to gas storage wells). This report includes a summary of shut-in pressures recorded on the annular spaces of each of the CINGSA storage wells and select annular spaces of the 15 third-party wells which penetrate the Sterling C Gas Storage Pool. Based upon a review of the available information associated with the 15 third-party wells which penetrate the storage formation, and the seven wells owned by CINGSA, there is no evidence of any gas leakage from the Sterling C Gas Storage Pool at the time this report was prepared. This analysis also included a review of historical production data from the 15 third-party wells noted above which penetrate the Sterling C Pool . Only seven of the fifteen wells remain in production; the other eight are either listed as “suspended,” “shut-in” or have been plugged and abandoned. Of the seven which remain in production, all are completed in and producing from the Beluga formation, which is immediately below the Sterling C Storage Pool. This includes CLU 01RD, CLU 05RD2, CLU 9, CLU 10RD2, and CLU 14-16 (CLU 01RD is dually completed and had also been producing from the Upper Tyonek, though production from that zone is currently listed as “shut-in”). The CLU 05RD2 well is also dually completed in and had been producing from the Tyonek D formation, though production data from the Tyonek D on the AOGCC website has not been updated since May 2023. Based upon a review of the production history of all seven wells, there is no evidence which suggests production from any of these wells is being influenced by CINGSA’s gas storage operations. In summary, operating data generally supports the conclusion that reservoir integrity remains intact, and although the reservoir is now effectively functioning as a larger reservoir due to encountering additional native gas in the Sterling C1c int erval of the CLU S-1 well, all the injected gas appears to remain within the greater reservoir and is accounted for currently. 2024-2025 Storage Operations The 2024-2025 storage cycle covers the period from April 15, 2024, the final day of the 2024 spring semi-annual shut-down, through April 21, 2025. Total inventory on April 15, 2024, was 13,498,572 mcf.1 Table 1 lists the remaining native gas-in-place as of April 1 Throughout this report, the term “Total Inventory” refers to the sum of the base gas in the reservoir plus the customer working gas in the reservoir. Total Inventory does not include the native gas CINGSA discovered when drilling the CLU S-1 well. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 6 1, 2012, net injection/withdrawal activity by month during the past 13 years, and the total gas-in-place at the end of each month since storage operations commenced. Note that the figures listed in Table 1 only include total inventory and have not been adjusted to include the estimated 14-24 Bcf of additional native gas associated with the isolated reservoir encountered by CLU S-1. The reservoir’s pressure vs. gas-in-place (total inventory) relationship has been monitored on a real-time basis since the commencement of storage operations to aid in identifying a loss of reservoir integrity. This type of plot is widely used in the gas storage industry. By tracking this data on a real-time basis, it is possible to detect a material loss of reservoir integrity. CLU S-3 was shut-in for most of the summer of 2012 and for a shorter period in 2013 so that wellhead pressure could be recorded for this purpose; thereafter it has been shut-in periodically to confirm the pressure versus inventory trend has remained consistent. Figure 1 is a plot of the actual wellhead pressure readings from CLU S-3 versus total inventory during the past seven storage cycles, from April 1, 2018, through April 21, 2025 (again, excluding the “found” native gas in the isolated reservoir). This plot also includes the expected wellhead pressure versus inventory response based on CINGSA’s initial storage operation design and computer modeling studies of the reservoir . The actual shut-in pressure of CLU S-3 initially aligned with simulated pressure from the modeling studies. However, at total inventory levels above approximately 11 Bcf, the shut-in wellhead pressure on CLU S-3 has been consistently higher than expected when compared to predicted shut-in pressure derived from initial computer modeling studies. The shut-in pressure readings have been trending approximately 300-350 psig above the Stabilized Wellhead Design Pressure. This higher observed pressure of CLU S-3 is attributable to an influx of a portion of the estimated 14-24 Bcf of native gas that CINGSA encountered when it completed the CLU S-1 well. The overall trend of the wellhead shut- in pressure of CLU S-3 versus total inventory plot has maintained a consistent and predictable linear trend; the trend supports the conclusion that there currently is no evidence of gas loss associated with storage operations, nor any other loss of well or reservoir integrity. More recently, CLU S-2 has been shut-in periodically to assess whether the wellhead pressure on it provides a more accurate indication of average reservoir pressure than CLU S-3. Figure 1 provides a comparison of the shut-in pressure vs. inventory data from these two wells. At this early stage of monitoring there does not appear to be a significant difference in the pressure vs. inventory trend of these two wells; pressure on CLU S -2 appears to be trending slightly lower than CLU S-3 at comparable inventory. CINGSA should continue to periodically record the shut-in pressure of CLU S-2 to determine CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 7 whether it continues to mirror the behavior of CLU S-3 over the broader range of operations. Facility Expansion During the 2024 injection season, CINGSA began work on a major expansion of the facility. The expansion consisted of the addition of two new 2750-horsepower Ariel KBC reciprocating compressors, a second gas conditioning train identical to the original train, and two new injection/withdrawal wells. These facilities were installed to support the expansion of the working gas capacity by two Bcf, from a total of 11 Bcf to 13 Bcf. The two new compressors were designed to achieve two key objectives. First, to enable higher injection pressure than the original two units can accommodate for the incremental 2 Bcf of working gas. Secondly, they are capable of operating at lower injection flow rates than the original two units and will better match the injection requirements of CINGSA’s customers without the need to recycle a portion of the injection stream. This will save fuel and unnecessary wear and tear on the compressor units. The additional gas conditioning train was needed to accommodate the incremental withdrawal deliverability associated with the two new wells. It will also provide some measure of redundancy in throughput in the event of a partial outage of the original train. The two new wells combined, CLU S-6 and CLU S-7, were designed to provide additional injection capability of up to 75 mmcf/d and withdrawal capability of up to 65 mmcf/d. Thus, maximum injection capability is increased to 225 mmcf/d and maximum withdrawal capability to 215 mmcf/d with the newly installed facilities. Neither well was available for service until the conclusion of the 2024-2025 withdrawal season. Thus, as of the date of this report no sustained operational flow data is available for either well, however, pressures are being recorded on both wells and CLU S-7 has undergone an initial back-pressure test, which is discussed in greater detail in the next section of this report. The wellbore locations of the two new wells were selected based on advanced processing of seismic data which helped identify key reservoir attributes. That work was completed during 2018-2019. CLU S-6 well was completed along the central west flank of the reservoir; it is believed than none of the original five wells effectively drain this area based on the seismic data. Immediately after perforating/completion the CLU S-6 exhibited higher than anticipated wellhead pressure; pressure was approximately 100-150 psi greater than the average CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 8 field pressure at that time. An initial test of the well resulted in the wellbore loading up with water; the well would not sustain gas flow. As of the date of this report, the CLU S-6 remains shut-in for pressure monitoring to better understand how it may be connected to the greater reservoir. This should remain the case for at least the first two months of the injection season or until pressure influence from injections into the greater reservoir is established. Thereafter some injections may occur but should be limited until the well is able to sustain flow without loading up with water. The well should also be tested while on injection. The CLU S-7 well was completed in the northeast section of the reservoir, east of the CLU S-1 wellbore. Seismic data indicated the possibility of good/excellent reservoir quality in this region – the same area that is believed to be the source of the incremental native gas encountered by CLU S-1 when it was originally completed. Initial shut-in pressure readings on CLU S-7 track very closely to those of CLU S-1. An initial back- pressure test of CLU S-7 revealed what appears to be excellent flow potential, though the well produced a measurable quantity of water during the test. Thus, it remains to be seen whether it’s production characteristics will mirror those of CLU S-1, which up to this point has consistently exhibited the highest deliverability of any of the CINGSA storage wells. Injections into CLU S-7 should be withheld initially until an interference test can be conducted via injections into CLU S-1 while monitoring shut-in pressure on CLU S-7. This test will yield valuable information concerning the subsurface connection of these two wells. The wellbores of CLU S-6 and CLU S-7 provide new data regarding the structural and internal attributes (the five sand intervals) of the Sterling C Pool. The structural map of the Pool has been updated accordingly and is addressed in a separate report/document. Both CLU S-6 and CLU S-7 will be more fully evaluated as the 2025 injection season progresses. Well Deliverability Performance The CINGSA facility is equipped with a robust station control automation and data acquisition (SCADA) system, which includes the capability to monitor and record the pressure and flow rate of each well on a real time basis. Monitoring well deliverability is an essential element of storage integrity management because a decline in well deliverability may be symptomatic of a loss of well integrity. It may also be an indication of well-bore damage caused by contaminants such as compressor lube oil, or formation of scale across the perforations, etc. Throughout the injection and withdrawal seasons, the deliverability of each well has been monitored via the SCADA system so that individual well flow performance could be tracked against past performance and the results of prior back-pressure tests performed on each well. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 9 Flow performance data from the 2024-2025 injection and withdrawal seasons were reviewed to assess how each well’s flow contribution compared to historical data. During the injection season, the flow contribution from each of the five original wells was consistent with historical patterns. CLU S-1’s contribution to total flow was about 40 percent, while that of CLU S-2, S-3, S-4, and S-5 was 20, 23, 9, and 7 percent, respectively. During the withdrawal season, utilization of the wells differed from the past. For example, CLU S-1 was open for withdrawals only 68 out of nearly 180 days. This significantly impacted the total gas withdrawn from this well; its contribution amounted to only 12 percent of the total gas withdrawn, which appears significantly below historical performance. In contrast, CLU S-2 and S-3 contributed 33 and 31 percent, respectively, while S-4 and S-5 contributed 14 percent and 10 percent respectively to total season withdrawals. These figures reflect the change in well utilization and not a decline in deliverability performance per se. There is no evidence which suggests that the performance of CLU S-1 has somehow declined; the injection data clearly indicates this well remains the best performing well of the original five wells. Since converting the field to storage, CLU S-5 exhibited a tendency to water-off during the withdrawal season. CINGSA installed a velocity string in this well in October 2020 to aid in keeping the well free of liquid accumulation (though the well was not restored to full service until October 2021). During the 2024-2025 withdrawal season from October-March, CLU S-5 produced approximately 326 mmcf, or 9.6 percent of the total withdrawal volume. During the 2023-2024 withdrawal season, CLU S-5 contributed 6.4 percent of the total withdrawals from October-March, and about 343 mmcf of gas. During the 2022-2023 season the well contributed 294 mmcf to net withdrawals, or 8.2 percent of the total for that season. During all three withdrawal seasons CLU S-5 produced more gas and more consistently than any year during the October- March period since the commencement of storage operations. These metrics continue to demonstrate that the velocity string achieved its intended purpose of helping to keep the wellbore free of liquid loading and significantly improved the withdrawal reliability of CLU S-5. CINGSA conducted back-pressure tests on CLU S-1, CLU S-2, CLU S-3 and CLU S-7 during March and April 2025. The test results on CLU S-1 confirmed that the coiled tubing clean out of this well in February 2024 was successful in fully restoring its long - term deliverability potential. Test results on CLU S-2 confirmed that the deliverability of this well has remained constant over the past 10 years. CLU S-3 was also cleaned out with coiled tubing in February 2024. Test results on it indicate the treatment may not have been successful at full restoration of deliverability potential; under peak withdrawal conditions it appears that deliverability capability is CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 10 lower by 20-30 percent relative to its capability in 2019. That said, there was a partial standing liquid column in the well at the time of testing, and this may have impacted well performance. The test results from CLU S-7 look very encouraging; its deliverability capability appears to be at least as high as CLU S-1, and possibly higher, though the well produced a fair amount of water during the test. Thus, it remains to be seen whether this newest addition to the CINGSA facility will perform as reliably as CLU S-1. The CLU S-6 well should be tested as the opportunity presents itself during the up-coming injection season. CINGSA has a process for monitoring sub-surface wellbore conditions that may impact well deliverability. It includes running fluid level surveys each month in all seven wells to monitor water influx into the wellbore, and bailer runs periodically in select wells to check for solid fill. However, the horizontal configuration of the wells makes confirming wellbore liquid/solid fill challenging. Confirming the presence of solid fill is difficult because the bailer tools are unable to reach total depth due to friction and gravity (the bailer tool only falls to the point where the wellbore becomes horizontal). The use of a video camera and tractor system may provide a more definitive method for investigating sand/silt fill in the wellbore; CINGSA should consider this approach as an improvement to operational reliability and deliverability monitoring. These tools are typically run via electric-line and may provide a more definitive method for assessing wellbore fill. Based on the most recent back-pressure test results, CLU S-1 and CLU S-7 exhibit the greatest deliverability capability of all seven wells, potentially contributing about 30 and 40 percent respectively of total field flow during withdrawals. Similarly, wells CLU S-2, S-3, and S-4 have the potential of contributing approximately 12, 10, and 7 percent, respectively. CLU S-5 has historically contributed about 1-8 percent of the total flow depending on the amount of water in the wellbore. A comparison of actual flow data from the original wells supports the results of their back pressure tests. Thus, the back-pressure test process and results represent a good proxy for what may be expected in terms of actual well deliverability . Based on the recent test results, it appears that field deliverability is adequate to meet CINGSA’s contract obligations, including those associated with the recently completed expansion project. 2024 Injection Season Operations and September 2024 Shut-in Pressure Test The field was released for resumption of active storage operations on April 15, 2024. During the remainder of April, the field was used mostly for withdrawals. Monthly injections for the duration of the summer months were modest, ranging between 11-44 mmscf/d. Peak injection rates rarely exceeded 50 mmcf/d. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 11 The field was shut-in for pressure stabilization the morning of September 9th and remained shut-in until the morning of September 16th. Total gas inventory on September 9th was 16,906,401 mscf, which included 9,906,401 mscf of customer working gas plus 7,000,000 mscf of CINGSA base gas. Table 2 lists the wellhead shut-in pressure for all five wells each day during the shut-in period. It also lists the day-to-day decline in pressure and the overall weighted average pressure of all five wells. On the final day of shut-in, wellhead pressures ranged from a low of 1667.7 psig on CLU S-3 to a high of 1684.5 psig on CLU S-1. Wellhead pressures did not fully stabilize during the week-long shut-in; average field pressure on the final day of shut-in decreased at a rate of approximately 1.7 psi/day. Figure 2 is a plot of the shut-in wellhead pressure of each well and the weighted average wellhead pressure for all five wells. The weighted average wellhead pressure on September 16th was 1676.0 psig and the average reservoir pressure was 1901.4 psia. Table 4 provides a summary of the surface and reservoir pressure conditions and the total gas-in-place at the time the reservoir was discovered. It also lists the same data for the 26 shut-in periods since commencement of storage operations. Lastly, it lists the gas specific gravity, the percentage of nitrogen and carbon dioxide contained in the storage gas, reservoir datum depth, and reservoir temperature. NOTE, no adjustment has been made at this time to CINGSA’s accounting records nor to the Total Gas-in-Place figures listed in Table 4 to reflect the additional native gas encountered in the isolated reservoir. Table 5 is a modified version of Table 4; this version has been adjusted to reflect the Total Gas-in-Place as if the Sterling C Pool and the isolated reservoir are connected and functioning as a single larger reservoir. Thus, the Total Gas-in-Place listed in Table 5 reflects the storage inventory currently listed in CINGSA’s accounting records plus an additional 14,500,000 mscf (14.5 Bcf) of native gas associated with the isolated reservoir , which reflects the lower end of the estimated range associated with the found native gas. Figure 4 is a plot of the average bottom hole pressure adjusted for compressibility (BHP/Z) versus gas-in-place during each of the past ten shut-in pressure tests compared to the original discovery pressure conditions. Linear regression analysis of these same data points since the commencement of storage operations indicate there is a strong and consistent linear correlation between reservoir pressure and inventory (gas-in-place); the regression coefficient (R2) is 0.969. In other words, since commencing storage operations in April 2012, the reservoir pressure versus inventory relationship has exhibited a very consistent and repeatable pattern. Note, the observed BHP/Z values for all shut-in periods in Figure 4 plot above the original pressure-depletion line. The reason for this is that CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 12 there has been no adjustment to total inventory in this plot to account for volume of “found” gas encountered by the CLU S-1 well. 2024-2025 Withdrawal Operations and April 2025 Shut-in Pressure Test After the fall shut-in test, the field experienced modest net withdrawals for the remainder of September. October, November, and December activity consisted of net withdrawals of 879 mmcf, 747 mmcf and 398637 mmcf, respectively. January and February customer activity resulted in withdrawals of 243 mmcf and 387 mmcf, respectively, which was followed by injections in March of 409 mmcf. The net withdrawal volume during the October-March 2024-2025 season was approximately 2,245 mmcf, which is slightly below the historical average of 2,485 mmcf. Field Operations reported that approximately 2310 barrels of water were produced during the withdrawal season. The field was shut-in for pressure stabilization and monitoring on the morning of April 14th and remained shut- in until the morning of April 21. Total inventory on April 14 was 14,173,761 mscf, which included 7,173,761 mscf of customer working gas and 7,000,000 mscf of CINGSA-owned base gas. Table 3 lists the wellhead shut-in pressure for all seven wells each day during the shut- in period. It also lists the day-to-day change in pressure and the overall weighted average field pressure for the original five wells and the arithmetic average pressure for all seven wells. Table 3 lists both averaging methods to provide a comparison of the two. The original five wells used a weighting factor to arrive at an estimate of field average pressure. The weighting factor was based upon the estimated drainage area of each well derived from a three-dimensional reservoir simulation. That model is no longer available, so it was not possible to update it to derive a drainage area/weighting factor for the two new wells. Going forward, the field average pressure will be derived using a straight arithmetic average of all seven wells. As is clear from the data in Table 3, the difference between the two averaging methods is small and will not result in a material impact on conclusions regarding the results of the material balance analysis. On the final day of shut-in, wellhead pressures ranged from a high of 1,531.4 psig on CLU S-6 to a low of 1,392.1 psig on CLU S-7. Field average pressure had not stabilized but was increasing at a rate of about 0.6 psi/day on the final day of shut in. Figure 3 is a plot of the shut-in wellhead pressure of each of the seven wells, the overall field weighted average wellhead on the original five wells, and the arithmetic average pressure or all seven wells. The overall field arithmetic average wellhead pressure on April 21st was 1,437.8 psig and the average reservoir pressure was 1,630.2 psia. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 13 Table 4 provides a summary of the surface and reservoir pressure conditions and the total gas-in-place at the time the reservoir was discovered. It also lists the same data for the 26 shut-in periods since commencement of storage operations. Lastly, it lists the gas specific gravity, the percentage of nitrogen and carbon dioxide contained in the storage gas, reservoir datum depth, and reservoir temperature. Figure 4 is a plot of the average bottom hole pressure adjusted for compressibility (BHP/Z) versus gas-in-place for each of the 26 shut-in pressure tests as compared to the original discovery pressure conditions. Linear regression analysis of these 26 data points indicates there is a strong linear correlation between the points; the regression coefficient (R2) is 0.969. Thus, like Figure 1, Figure 4 strongly supports the conclusion that reservoir integrity is intact. The key point to note is that the observed BHP/Z values for all 26 of the shut-in tests since commencement of storage operations are above the original pressure-depletion line, which provides very compelling evidence that integrity is intact, and the reservoir and wells are not losing gas. Figure 5 is a plot of this very same shut-in data but includes an additional 14.5 Bcf of native gas (low end of the range estimate) associated with the isolated reservoir. In this plot, the Sterling C Pool and the isolated reservoir are treated as a single common reservoir which together contained a total of approximately 41 Bcf of gas prior to their discovery (26.5 Bcf in the main reservoir and 14.5 Bcf in the isolated reservoir). A linear regression analysis of the 26 shut-in points, and assuming the isolated reservoir was at native pressure conditions at the time the CLU S-1 well was completed, yields a regression coefficient (R2) of 0.950. The strong linear correlation between the shut-in reservoir pressure and total inventory for the two combined reservoirs since the commencement of storage operations provides compelling evidence that there has been no material loss of gas from the reservoir . It also supports the current estimate of additional native gas associated with the isolated reservoir. Thus, Figures 4 and 5 strongly support the conclusion that reservoir integrity is intact, and that there is no evidence of a material loss of storage gas from th e storage facility. Estimate of Additional Native Gas Volume As explained in prior annual reports, CINGSA encountered an isolated reservoir of native gas which was possibly still at native discovery pressure when CLU S-1 was initially perforated/completed. Wellhead pressure on the CLU S-1 well rose to approximately 1,600 psi within a few days after completion, while wellhead pressure on the remaining four wells was approximately 400 psi, which was in line with expectations. The C1c sand interval is one of five recognized sand intervals that are common to nearly all the wells that penetrate the Cannery Loop Sterling C Pool. This sand interval was also one of the CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 14 perforated/completed intervals in the CLU-6 well – the sole producing well during primary depletion of the Cannery Loop Sterling C Pool. Following initial perforation/completion, a temperature log was subsequently run in CLU S-1 to identify the nature and source of the higher pressure. The temperature log exhibited compelling evidence of gas influx from the sand interval which correlates to the Sterling C1c sand interval. The higher-than-expected shut-in pressure and evidence of gas influx strongly suggest the C1c was indeed physically isolated from the other four sand sub - intervals within the Sterling C Pool. It is unknown whether the C1c sand interval was at native pressure (2200 psi) at the time CLU S-1 was completed, or if it had been only partially depleted . If fully isolated from the pressure-depleted section of the reservoir, completion of the C1c effectively adds to the remaining native gas in the reservoir. This additional gas also accounts for the weighted average reservoir pressure during each of the 24 field-wide shut-in pressure tests plotting above the original BHP/Z versus gas-in-place line. This previously isolated pocket of native gas provides pressure support to the storage operation and effectively functions as additional base gas. Two independent methods are being used by CINGSA to estimate the volume of incremental native gas encountered by the CLU S-1 well. The first method is based on a material balance analysis which was performed using the shut -in reservoir pressure data gathered during each of the past semi-annual shut-in tests, including the most recent in September 2023, and April 2024, together with observed shut-in pressures from CLU S- 3 to estimate the magnitude of additional native gas encountered in the C1c sand interval of CLU S-1. The approach used to analyze this data was to treat the originally defined reservoir and the previously isolated C1c sand interval as two separate reservoirs that became connected during perforation/completion work on the CLU S-1 well. A simultaneous material balance calculation on each reservoir was made in which hydraulic communication was established between the two reservoirs because of completion of CLU S-1 in late January 2012. Gas could migrate between the reservoirs. The connection between the reservoirs was computed by defining a transfer coefficient which, when multiplied by the difference of pressure-squared between the two reservoirs, results in an estimated gas transfer rate. In other words, as storage gas is injected and withdrawn from the original reservoir it is supplemented by gas moving from or to the C1c interval of the “found” reservoir according to the pressures computed in each reservoir at any given time. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 15 The volume of gas contained in the original reservoir was well defined from the primary production data; initial gas-in-place was determined to be 26.5 Bcf. The volume of gas associated with the C1c sand interval in CLU S-1 and the transfer coefficient was varied to match the observed pressure history using a day-by-day dual reservoir material balance calculation. Figures 6, 7 and 8 illustrate the results of the dual reservoir material balance procedure. Figure 6 illustrates the actual average reservoir pressure during each of the 26 shut-in periods versus the dual reservoir model (DRM)-computed reservoir pressure. It also illustrates the observed CLU S-3 pressure when that well is shut-in versus the DRM computed pressure. In both cases the DRM yielded a good match between actual observed bottomhole pressure versus bottomhole pressure computed by the model, particularly during the first 7-8 years of operation. Generally speaking, the match between actual and computed pressure has been closer for the spring shut-in pressure than during the fall. Figure 7 illustrates the daily transfer rate and the estimated cumulative net transfer of gas into the Sterling C Pool through storage history. As of the spring 2025 shut-in pressure test, the DRM indicates there has been approximately 4.1 Bcf of net gas transfer into the depleted Sterling C Pool (assuming the isolated pocket contained 14.5 Bcf of gas when it was encountered by the CLU S-1 wellbore). When the model was initially developed various combinations of additional native gas volume in the isolated reservoir and transfer coefficients were explored. A range of additional native gas volumes from 14-16 billion standard cubic feet (Bcf) were evaluated to see which volume yielded the best match to actual reservoir pressure. Through approximately 2020, a volume of 14.5 Bcf of gas associated with the isolated pocket yielded acceptable matches with the actual shut-in reservoir pressure conditions. However, since that time there appears to be an increasing difference, albeit gradual, between the actual reservoir pressure and that computed by the DRM, particularly during the fall shut-in pressure tests. It is noteworthy that storage inventory has been on an increasing trend coincident with this same period (since 2020), though that may or may not be the reason that the observed reservoir pressure has started to deviate from reservoir pressure computed by the DRM. A second explanation is that the volume of gas associated with the isolated pocket was larger than originally assumed. Figure 8 illustrates the same data as Figure 6 except that it assumes the isolated pocket of native gas was 24 Bcf, or 10 Bcf larger than initially assumed in the DRM. This adjustment appears to improve the overall pressure match during the most recent 4-5 years without materially degrading the match during the first 7-8 years of storage CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 16 operations. Thus, it is possible that the isolated pocket of native gas was larger than initially believed based on these results using the DRM. That said, a 4–5-year trend is judged to be too limited from which to render a definitive revision to the volume of gas associated with the isolated pocket of native gas. As noted above, storage inventory has been trending higher in the past 4-5 years, and this could be a contributing factor. Additional time and storage cycles may provide greater insight into what is driving this behavior. In the interim, the improvement in the match between actual reservoir pressure versus the DRM-computed reservoir pressure suggests a volume range of 14- 24 Bcf gas associated with the isolated pocket may be indicated and more appropriate than the previous range of 14-16 Bcf. The second method used by CINGSA to estimate the volume of incremental native gas encountered by CLU S-1 is a three-dimensional computer reservoir simulation model. The initial modeling effort utilized an existing reservoir description/geologic model which was updated in 2014 after the drilling and completion of the five injection/withdrawal wells. It incorporated all available well control data and petrophysical data from electric line well logs, and seismic data that was used to characterize channel boundaries and differentiate possible reservoir versus non-reservoir rock. This simulation work yielded an initial estimate of 18 Bcf of gas associated with the isolated reservoir, or about 2-3.5 Bcf larger than the dual reservoir model. The 2014 modeling work was updated in 2016 and again in 2017 and 2019. The updated reservoir/geologic model incorporates the results of a more sophisticated seismic analysis which provided insight into the areal extent of the isolated reservoir that was contacted by the CLU S-1. The match between observed pressure and production data versus that computed by the reservoir model was generally within 50 -100 psi (which is considered good-very good) on wells CLU S-1, CLU S-2, CLU S-3 and S-4 over most of the operating history of these wells. The agreement between observed versus computed pressure and production was not as good on CLU S-5 (ranging between 100-150 psi). The estimated volume of incremental gas associated with the isolated reservoir that yielded the best history match was 19.5 Bcf in the 2019 update of the simulation model . This estimate is 3.5 Bcf greater than the highest estimate using the dual reservoir model. In comparing the results of the two modeling methods discussed above, there is relatively good agreement between the two, with the range of “found gas” falling between a low of 14 Bcf to a high of as much as 23-24 Bcf. While this range is greater than what was reported during the early years of operation, it nonetheless remains small, particularly considering the full working gas inventory has never been cycled since placing the reservoir into storage service and the limited extent of the isolated reservoir that is in contact with the CLUS-1 well. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 17 With greater cycling of the working gas capacity, it is possible that the difference in the estimated additional native gas derived using the two different modeling methods may narrow. The drilling and completion of CLU S-7 may also shed more light on this issue depending on the pressure and flow behavior of the well. It will likely take a couple of storage injection and withdrawal cycles to fully assess its value in further characterizi ng the volume of found gas. In the interim, the 14.5 Bcf estimate associated with the dual reservoir material balance analysis was used once again in this year’s assessment. Measurement Calibration Checks The CINGSA facility operates with two custody transfer meters, one of which is connected to the “CINGSA lateral” and the other to the KNPL pipeline. The Measurement Department performs monthly calibration checks on both meters to confirm they are performing within the manufacturer’s specifications. If a loss of calibration were to occur resulting in a measurement error impacting storage inventory, Measurement would alert Operations and Gas Accounting and an adjustment to the storage inventory would be posted to correct the measurement error. No adjustments to storage inventory were required during the period May 1, 2024, through April 2025. Compressor fuel and station usage along with station blowdowns, and other losses (LAUF) are accounted for each month and inventory is adjusted, accordingly. Monthly fuel usage from May 2024-April 2025 averaged approximately 1.6 percent of the injected volume, which is down significantly from the May 2023 – April 2024 period of 1.9 percent and is now within historical averages which have ranged from 1.5-1.7 percent. Lost and unaccounted for (LAUF) volume during this same period averaged 0.06 percent of throughput volume, which is within historical norms. Table 1 provides a summary of the monthly injection/withdrawal volumes, compressor/station fuel usage, and losses since the commencement of storage operations. Annulus Pressure Monitoring Each of the CINGSA wells were constructed to the highest of industry and regulatory standards, including installing tubing set on a packer inside of the production casing. All flow is through the tubing string. This configuration (flow through tubing set on a packer) satisfies international well construction standards listed in ISO 16530 and is consistent with the “double barrier” requirements for flow containment. This configuration meets the Alaska Oil and Gas Conservation Commission’s storage well construction requirements and exceeds the new PHMSA gas storage well construction requirements . It provides two complete layers of protection against gas loss/leakage from the wellbore. By monitoring pressure in the annulus between the production tubing and intermediate CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 18 casing, it is possible to identify a loss of tubing integrity which, if left unchecked, could potentially result in a loss of storage gas. Prior to CINGSA commencing storage operations, all the Marathon Alaska Production Company (now Hilcorp Alaska LLC) wells that penetrate the Sterling C Gas Storage Pool were subjected to AOGCC-mandated Mechanical Integrity Tests (MIT), and all the wells successfully demonstrated integrity. Shortly after commencing storage operations, all the CINGSA wells were also subjected to MITs, and they likewise demonstrated integrity . All five of the original CINGSA wells were retested in 2016, 2020, and 2024 and all five wells passed the MIT. The two new CINGSA wells were likewise subjected to an MIT prior to placing them in service; both wells passed their MIT. Hilcorp’s wells which penetrate the Cannery Loop Sterling C gas storage reservoir are subject to the same periodic MIT’s and had been on the same testing cycle as CINGSA’s storage wells up until last year. Hilcorp’s wells are due for testing this year (2025) to remain in compliance with AOGCC’s requirements. On wells CLU S-1 – CLU S-4, CLU S-6 and CLU S-7 CINGSA monitors and records pressure on both the tubing/intermediate casing string annulus (7” x 9 5/8”) and intermediate/surface casing string annulus (9 5/8” x 13 3/8”) to identify any evidence of loss of well or reservoir integrity. The same is true for CLU S-5 except that the annular space of the inner string is 3 ½” x 9 5/8”. In addition, Hilcorp monitors and records pressure monthly on each of the annular spaces of its production wells which penetrate the Sterling C. Hilcorp also monitors and records pressure on the tubing string in certain wells monthly. Hilcorp provides a copy of this data to CINGSA each month and CINGSA reviews the data for any evidence of a loss of well/reservoir integrity, in the same manner as it does for its own wells. All these annulus pressure readings are submitted monthly to the AOGCC and are part of routine and ongoing surveillance activities to identify issues which may indicate a loss of integrity of the storage operation. Figures 9-15 illustrate the historical tubing and annulus pressures on each of the CINGSA gas storage wells. Inner annulus pressure (and to a much lesser extent the outer annulus pressure) on all the CINGSA storage wells rises and falls with the tubing pressure, albeit at a lower level. The inner annulus (7” x 9 5/8” for wells 1-4 and 6 and 7, and 3 ½” x 9 5/8” for well 5)) is filled with brine and diesel. The outer annulus (9/58” x 13 3/8”) of the original five wells is filled with cement, to surface; CINGSA was unable to circulate cement to surface on this annular space of the two newest wells. A more pronounced pressure swing is typically observed on the inner annulus than the outer. In both cases, the pressure swing appears to be due entirely to expansion of the tubing string which results from higher pressure and higher injection gas temperature when injections are occurring. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 19 Any annulus pressure which equals the tubing pressure and tracks with changes in the tubing pressure may be indicative of a loss of tubing and/or tubing seal integrity and warrants investigation. The AOGCC requires that CINGSA maintain a positive pressure on the inner annulus of each storage well (typically 200-500 psi). A loss of this pressure may be indicative of a loss of integrity. Both scenarios mentioned above require CINGSA to immediately (within 24 hours) notify the AOGCC of a potential loss of integrity and remove the well from service. Observed annulus pressure on all seven of the CINGSA wells has always been less than the tubing pressure. Each of the wells has also maintained positive pressure on the innermost annulus throughout history except for CLU S-7. The innermost annulus of this well was initially charged to 180 psi on March 4, 2025, Over the course of 2-3 days pressure declined to 30-40 psi. Operators recharged this annulus to 220 psi on March 24, and again pressure declined to about 20 psi over the course of about a week. It was repressurized again on two subsequent occasions in April, at one point to a high of 360 psi. As of the date of this report, the inner annulus exhibited a residual pressure of 90 psi, though pressure was still declining. This may be indicative of a minor wellhead seal leak and should be investigated and resolved. With the caveat of the unresolved annulus pressure on CLU S-7, this observation supports the conclusion that tubing, tubing wellhead seal, and the tubing/packer element seals remain intact and there is no evidence of a loss of integrity in any of the five CINGSA wells. Figures 16-30 illustrate similar data on each of the Hilcorp wells that penetrate the Sterling C gas storage pool. Hilcorp drilled and completed a new well in 2024 to the deeper Beluga formation—the CLU-16 well—and monthly monitoring of the annulus pressure of this well is now included in the overall annulus pressure program. All the current annulus and tubing pressure readings on the Hilcorp wells are low (below 200 psi) and do not track the CINGSA well tubing pressure trends. This lends support to the conclusion that the Hilcorp wells are isolated from the storage interval and do not exhibit any evidence of a loss of storage integrity. That said, of the 15 wells that are owned by Hilcorp and subject to annulus pressure monitoring, three have exhibited annulus pressure in recent years that warrant comment. This includes CLU 04, CLU 05RD, and CLU 15. Annulus pressure on CLU 04 has remained near zero on both the 3 ½ x 13 5/8-inch annulus and 13 5/8 x 20-inch annulus (collectively the outer annuli) since the beginning of storage operations in 2012. In November 2022, surface pressure on both spaces increased to 150-160 psig and remains elevated at that level as of the date of this report, CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 20 while the production tubing pressure has remained in the 10-25 psi range. While this represents a modest increase in pressure on the outer annuli, the sudden increase nonetheless warrants a discussion with Hilcorp as to a cause and whether investigative steps are warranted. Pressure on the 3 ½ inch x 9 5/8-inch annulus on the CLU-05RD2 well began rising in early 2016 and reached a high of almost 850 psig before flattening out (see Figure 19). The 9 5/8-inch x 13 3/8-inch (outer) annulus currently exhibits a pressure of about 15 psig. The 9 5/8-inch string penetrates the storage zone and was originally cemented off across the storage interval. However, this well was side-tracked in late 2015. An 8 1/2- inch window was milled through the 9 5/8-inch casing at 6527 feet measured depth (5354’ true vertical depth), which is just below the storage interval in the Beluga formation. A 7 5/8-inch liner was set on a liner top packer inside of the 9 5/8-inch string at a depth of 6433 measured depth; it was run through the window to a measured depth of 10448 feet and was cemented in place as the new intermediate casing string . A 4 ½ inch liner was set and cemented in the Tyonek at a measured depth of 12915 feet . A cement bond log was run on the 7 5/8-inch liner, but it was not possible to determine the top of cement behind the 7 5/8-inch string from the log data. CINGSA contacted Hilcorp in May 2018 to understand the source of the pressure on the 3 ½ x 9 5/8-inch annulus, and to determine whether the elevated pressure could be indicative of pressure communication with its storage operations . Hilcorp agreed to investigate the issue and attempt to blow down pressure on the 3 x 9 annulus of the CLU - 05RD well. When the blow down attempt was made the annulus was found to be filled to the surface with liquid – no gas was present. Pressure on the 3 x 9-inch annulus was approximately 200 psi during the September 2022 CINGSA shut-in test but has since declined to less than 30 psig. In a similar vein, annulus surface pressure on the 4 ½ x 7 5/8-inch strings (inner annulus) of the CLU 15 well increased gradually after this well was placed into production in 2020. It reached a peak of approximately 210 psig in 2023 but has declined gradually to under 150 psig. Surface pressure on the outer 7 5/8 x 10 ¾ inch outer annulus has remained near zero psig. The 7 5/8-inch casing string is set and cemented through the base of the Sterling C gas storage pool, and the top of cement behind the 4 ½ inch tubing appears to b e several hundred feet above the top of the Sterling C. The production tubing pressure on CLU 15 has ranged from 200-250 psi since the well came on production. Thus, it seems unlikely that the source of pressure on the 4 ½ x 7 5/8-inch annulus is related to an integrity issue that involves the Sterling C gas storage pool. Rather, it appears to be associated with a minor leak in the 4 ½ inch tubing or the tubing wellhead seals. At this stage, further investigation does not appear warranted, though continued monitoring by CINGSA is certainly in order. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 21 Based on a thorough review of the annular pressure data for all wells which penetrate the storage formation, there is no evidence of a loss of integrity of any of the CINGSA injection/withdrawal wells. This data lends additional support to the conclusion that reservoir and well integrity is intact, and all the storage gas remains within the reservoir and is thus accounted for. Third Party Production A review of historical production data from 15 third party wells which penetrate the Sterling C Pool was completed to examine for evidence of pressure and/or flow communication from CINGSA’s storage operations. As of March 1, only seven of the fifteen wells remain in production, all of which are operated by Hilcorp; these include CLU-01RD, CLU-05RD2, CLU-9, CLU-10RD2, CLU-14, CLU-15, and CLU-16, which was newly drilled and completed in the Beluga during 2024 . The other nine are either listed as “suspended,” “shut-in,” or have been plugged and abandoned. Of the seven which remain in production, all are completed in and producing from the Beluga formation, immediately below the Sterling C Storage Pool (although both CLU 01RD and CLU 05RD2 are dually completed in both the Beluga and the deeper Tyonek). The production decline curves for ten of the wells which have produced in more recent years are included as Figures 31-42; the producing zone associated with each well is indicated on each of these figures. If any of Hilcorp’s production wells were acting as a conduit for gas leakage from the Sterling C Pool to either the Beluga or Tyonek formations via a poor cement job behind casing or a lack of casing integrity, it is likely that production from the offending well would either increase or remain flat for an extraordinary period. The production decline curves from Hilcorp’s wells do not appear to exhibit such behavior. Thus, none of their wells appear to be serving as a conduit for leakage of gas from the storage formation. Based upon a review of the production history of all seven wells which remain in production there is no evidence at the time this report was prepared which suggests production is being influenced by CINGSA’s gas storage operations. On August 3, 2020, CINGSA and Hilcorp entered into a written agreement which obligates the two entities to share certain information with each other related to well drilling, completion, production, and workover activity for existing and future wells. The data includes, but is not limited to, drilling and rework permit applications, downhole logging data, survey data, and pressure and production data, all as it relates to wells which penetrate the Sterling C Pool. Each party also has an affirmative obligation to report to the other any well condition which may indicate a loss of integrity. The written agreement provides a framework which will help ensure the integrity of each party’s wells/reservoirs while satisfying the requirements of CO231A. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 22 Hilcorp failed to honor the above referenced agreement when it completed the CLU 10RD2 wellbore – a directional sidetrack of the CLU 10RD. They did not run a cement bond log on the casing string which penetrates and isolates the Sterling C Pool. Thus, CINGSA has no knowledge of the cement bonding of this wellbore across the gas interval. During the past 36 months Hilcorp implemented an aggressive rework/recompletion program that involved nine of its wells, all of which penetrate the Sterling C Pool . In addition, they drilled and completed a new well in the Beluga during 2024. As part of the written agreement referenced immediately above, Hilcorp provided CINGSA with a copy of their proposed plans for each of these wells. The following is a summary of the work performed on each of these wells. CLU 01RD: This well produced from the Upper Tyonek through April 2021, at which time production ceased. In May 2022, Hilcorp perforated the Lower, Middle, and Upper Beluga in this well. The uppermost perforations are now 167 feet below the base of the Sterling C Pool. A velocity string was installed in this well in December 2023 to aid in the well’s ability to unload wellbore fluid. The Beluga remains on production as of the date of this report. CLU 05RD: This well was side-tracked to a new bottomhole location as CLU 05RD2 in September 2022. The new wellbore was then perforated in the Tyonek D and the Middle Beluga. The uppermost perforations are now 133 feet below the base of the Sterling C Pool. The last reported production from the Tyonek D was May 2023; the Beluga remains on production. CLU 7: Hilcorp filed a permit to perforate and stimulate the CLU 7 well in February 2022. The proposed perforation/stimulation interval was the Upper Beluga 1X interval, which is only 56 feet below the base of the Sterling C Pool. CINGSA raised an objection to this proposed plan with Hilcorp and the AOGCC due to the proximity of the perforations to the base of CINGSA’s gas storage interval. Hilcorp elected to not proceed with this work. The most recent production from this well was December 2021. It is currently listed as shut in. CLU 8: Hilcorp performed a coiled-tubing cleanout on CLU 8 in July 2022. No new intervals were perforated. This well had been the subject of attention in prior annual reports because of similar pressures on it and CINGSA’s storage operations. However, production from this well has fallen dramatically in the past two years. Thus, currently there does not appear to be any hydraulic connection between this well and CINGSA’s CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 23 storage operation. This well last produced in September 2023 and is currently listed as shut in. CLU 9: In May 2022, Hilcorp filed an application with the AOGCC to perforate additional sections of the Lower and Upper Beluga in CLU 9 . The proposed uppermost perforation would have been 177 feet below the base of the Sterling C Pool. There is no completion report on file, and production from the well has not changed so it appears that Hilcorp never performed this work; CINGSA should confirm with Hilcorp that is the case. The CLU 9 well has continued to produce from the Beluga at fairly constant rates since 2018. CLU 10: Hilcorp re-entered CLU 10 in December 2022 and side-tracked the well to a new bottomhole location as CLU 10RD. This well was subsequently perforated in the Upper Beluga in February 2023. The uppermost perforations are 250 feet below the base of the Sterling C Pool. This well produced less than 5 mmscf during the three-month period of August-October 2023, but thereafter it remained shut in until December 2024 when the well was once again side-tracked to yet another bottom hole location as CLU 10RD2. Perforation work was completed in the Beluga in early January and the well has since remained on production. The uppermost perforations were targeted at 342 feet below the base of the Sterling C Pool. As noted above, Hilcorp failed to run a cement bond log across the storage interval of this sidetracked well; as such, cement bonding across the storage interval in unknown. CLU 13: Between November 2022 and February 2023 Hilcorp added new perforations to this well. They perforated the Upper Beluga 3A interval and the upper-most perforations are now 176 below the base of the Sterling C Pool. There has been no production from this well since October 2023. CLU 14: In April 2022 Hilcorp added new perforations to the Upper Beluga in the UB3A interval. The uppermost perforations are now 203 feet below the base of the Sterling C Pool. This well is still being produced from the Beluga. CLU 15: In April 2022 Hilcorp added new perforations to the Upper Beluga in the UB3A interval. The uppermost perforations are now 187 feet below the base of the Sterling C Pool. This well continues to be produced from the Beluga. CLU 16: In March 2024 Hilcorp filed a permit to drill and complete this well with the AOGCC. The target formation was the Beluga. An intermediate string of 7 5/8-inch casing was set through the Sterling C Pool and cemented across that interval. Initial production commenced in June 2024 and production from the well continues as of the date of this report. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 24 Rule 3 of AOGCC’s SIO9 Under Rule 3 of SIO 9, CINGSA was required to install and maintain a gas detection and alarm system in the building adjacent to the location of the KU 13-08 plugged and abandoned gas well. It did so in 2012. CINGSA has found compliance with Rule 3 to be problematic. The problems encountered have ranged from third party communication provider issues to a faulty detector, but many callouts are due to no power being supplied to the equipment . CINGSA also believes that several of the faults and the detector failure were due to cycling power to the equipment. CINGSA has responded to Inlet Fish system alarms using the same protocol as the CINGSA facility. Inlet Fish has not accommodated access to their property for afterhours events, deferring to a “more reasonable” meeting time. In many instances when personnel are dispatched to Inlet Fish, access to the panels is obstructed with various equipment that must be moved or worked around. CINGSA personnel arrived onsite while the alarm was annunciating to find Inlet Fish employees performing their jobs as normal instead of evacuating the buildings. In a letter to the AOGCC dated February 22, 2022, CINGSA requested that the Commission exercise its discretion to administratively waive CINGSA’s compliance with Rule 3. Based on its actions and communication with CINGSA, it appears Inlet Fish’s concerns about its proximity to CINGSA’s operations and the plugged and abandoned well on its property have been alleviated. Despite the number of electrical disconnects, the manpower and incremental cost CINGSA has incurred to respond to false alarms, and its regular inability to access the equipment, CINGSA has been prohibited by Inlet Fish from operating and maintaining the required gas detection equipment. On May 10, 2022, the AOGCC published notice of a tentatively scheduled hearing on whether Rule 3 of SIO 9A should be rescinded. On May 9, 2022, AOGCC sent copies of the public hearing notice to Inlet Fish Producers, Inc. (IFP) and its parent company, E&E Foods. No comments were received from members of the public, or Inlet Fish Producers, Inc., and its parent company, E&E Foods. No requests for a public hearing were received. By Order dated June 22, 2022, the AOGCC ruled in part that 1) CINGSA’s application provided sufficient information upon which to make an informed decision on its request, 2) information provided by CINGSA shows gas detection equipment has been installed and maintained as required by SIO 9A, CINGSA made numerous efforts to resolve the issues surrounding operation of the gas detection equipment, 3) both IFP and its parent company E&E received notice of CINGSA’s request to rescind Rule 3 and neither IFP nor E&E provided any input regarding CINGSA’s application or requested a hearing, and 4) there has been no physical evidence provided to AOGCC supporting any claim that KU 13- 8 lacks mechanical integrity and there is no evidence of gas leakage from the CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 25 well. Accordingly, AOGCC approved CINGSA’s request to administratively amend Storage Injection Order 9A (SIO 9A) to rescind Rule 3. Summary and Conclusion CINGSA commenced storage operations on April 1, 2012, and has now completed 13 full years of storage operations. All the operating data associated with the CINGSA facility indicate that reservoir integrity is intact. The observed pressure vs. inventory trend is consistent with modeling studies of the reservoir prior to placing the facility in service, although wellhead shut-in pressure on CLU S-3 has trended above the stabilized pressure line developed from initial computer modeling studies of the reservoir. CINGSA completed a major facility expansion during the past 12 months. The expansion consisted of two new 2500 horsepower reciprocating compressors, a second identical gas conditioning train, and two additional wells. These facilities are now in service. The two new wells are CLU S-6 and CLU S-7, which are located along the west-central flank and northeast regions of the reservoir, respectively. Initial shut-in pressure on CLU S-6 was approximately 100-150 psi greater than average field pressure at the time. Initial shut-in pressure on CLU S-7 aligned very closely with that of CLU S-1, which is approximately 1000 feet to the west of it. CLU S-6 should remain shut-in for pressure monitoring for the first few months of the 2025 injection season so that its pressure can be monitored for influence from injections into the remaining wells. Thereafter the well should be back-pressure tested while on injection and the results evaluated before undertaking any further activities on this well. CLU S-7 should also remain shut-in for the first couple of months of the injection season while injecting into CLU S-1. This will aid in understanding the degree of pressure communication between these two wells and may aid in further characterizing CLU S - 7’s connection to the region of the reservoir believed to contain the found gas. The CLU S-1, CLU S-2, CLU S-3 and CLU S-7 wells were back-pressure tested in March and April 2025. Results of these tests indicate that the coiled tubing clean out performed on S-1 was successful at fully restoring peak-day deliverability performance, and results from S-2 confirm this well has maintained its performance capability over the past ten years. Test results from CLU S-3 indicate the coiled tubing clean out in February 2024 may not have fully restored its deliverability capability; peak withdrawal capability appears to be about 20-30 percent lower than historical levels, though fluid in the wellbore at the time of testing may be a contributing factor. An initial test of CLU S-7 suggests this well may be as strong a contributor to field deliverability as CLU S-1, though it made a measurable CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 26 quantity of water during the test. Thus, its true performance capability will be borne out only through operation. The CLU S-5 well was not tested during the 2024-2025 cycle, however, withdrawal data from this well continues to support the conclusion that the velocity string that was installed in 2021 achieved the intended purpose of improving deliverability reliabilit y. This well continues to produce more gas and more consistently than prior to installation of the velocity string. An initial test was attempted on CLU S-6, however the well quickly loaded up with water and gas flow ceased. Attempts should be made to test this well later in the 2025 injection season after monitoring pressure on the well for a couple of months. CLU S-1 and S-3 exhibited a precipitous decline in deliverability in January 2024 due to sand/silt invasion into the wellbore. Drawdown guidelines had been adhered to prior to this event so the cause is unclear. It may be that both wells had been experiencing gradual sand/silt influx for some time, albeit below what can be detected operationally. Both wells were cleaned out using coiled tubing in February. CINGSA should consider the periodic deployment of a video camera via electric line/tractor to investigate and confirm wellbore fill. This may provide an early warning of wellbore conditions that warrant cleaning out before well deliverability is impacted. Overall, the recent back-pressure test results indicate that field deliverability is stable and adequate to meet CINGSA’s contract obligations, including those associated with the recently completed expansion project. During the initial completion of the CLU S-1 well, an isolated pocket of native gas was encountered within the Sterling C1c sand interval. This gas has since commingled with gas in the main (depleted) portion of the reservoir, effectively adding to the remaining native gas reserves and providing pressure support to the storage operation. This additional gas is functioning as base gas and accounts for the higher-than-expected shut- in wellhead pressure readings on CLU S-3 and the field-wide shut-in pressures observed during each of the eight shut-in periods. Two independent methods have been used to estimate the volume of incremental native gas encountered by CLU S-1. The two methods yield estimates of the volume of this additional native gas which range from 14-24 Bcf. CINGSA performs semi-annual shut-in pressure tests on the reservoir and conducts an annual material balance analysis using that shut -in pressure test data. A total of 26 shut- in tests have been performed since commencement of storage operations . The field weighted-average shut-in pressure versus inventory relationship during the 26 semi- annual shut-in pressure tests conducted since converting the field to storage service CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 27 exhibit a strong linear correlation (R2 = 0.969). Thus, the results of these shut-in pressure tests support the conclusion that no loss of gas from the reservoir is occurring, and that all the injected gas remains within the storage reservoir. Annulus pressure readings on all the CINGSA wells demonstrate confinement of storage gas to the reservoir; none of the CINGSA wells exhibit anomalous annular pressure. Annulus pressure readings on each of Hilcorp’s production wells which penetrate the Sterling C Gas Storage Pool also support the conclusion that well mechanical integrity appears to be intact in each of Hilcorp’s wells; there is no evidence of pressure communication between the storage reservoir and Hilcorp’s production wells. CINGSA should continue to monitor the pressure of all the Hilcorp wells for any change in character which may be indicative of a loss of storage integrity. Ongoing production from Hilcorp’s wells, which penetrate the gas storage pool but are completed in the Beluga and Tyonek formations which are below the storage formation were evaluated to examine for evidence of production support from CINGSA’s storage operations. Seven wells which penetrate the storage field remain in production as of the date of this report. There is no compelling evidence of production support from CINGSA’s operations. Currently, production operations appear to be fully isolated from gas storage operations. During initial storage operations, the CLU S-3 well remained shut-in and wellhead pressure readings from it were routinely recorded and used to track the field pressure versus inventory relationship. This practice ceased in 2014 in favor of utilizing all wells for injections/withdrawals. Recently, CINGSA has begun the practice of shutting-in CLU S-2 periodically for several days to again correlate field pressure with inventory . This well may provide a reasonable indication of average reservoir pressure and CINGSA should continue this process to confirm whether the shut-in wellhead pressure on S-2 is indeed a valid proxy for average field pressure. A short field-wide deliverability test was performed during March 2015 at a storage inventory level of approximately 4.6 Bcf. The test results effectively confirmed the field can meet the aggregate MDWQ obligations of CINGSA’s customers at a working gas inventory of approximately 4.6 Bcf. Since that time CINGSA has implemented revised drawdown guidelines to mitigate the potential for wells loading up with sand /silt and/or watering off. The revised drawdown guidelines effectively limit the withdrawal capabil ity of the field relative to its capability under the original drawdown guidelines . CINGSA should consider performing similar field-wide deliverability tests in the future to validate withdrawal system capability. CINGSA has a policy which requires periodic testing and calibration of its custody transfer measurement system. The policy specifies that a health check be performed monthly for all ultra-sonic measurement systems such as the type installed at the CINGSA CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 28 facility. Operations personnel confirmed that these monthly tests have been performed routinely. No adjustments to meter volumes were necessary during the period of May 1, 2024, through April 2025. There is no evidence of any material measurement error based on the results of the material balance analysis. Based upon a thorough review of available operating data, storage reservoir integrity remains intact. Although the reservoir may now be effectively larger than expected due to encountering additional native gas in the Sterling C1c interval of the CLU S-1 well, all the injected gas remains with the greater reservoir and is accounted for at this time. CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 29 Table 1 – Monthly Injection and Withdrawal Activity Month Injections - Mcf Withdrawals - Mcf Compressor Fuel & Losses -Mcf Total Gas in Storage - Mcf Mar-12 0 0 0 3,556,165 Apr-12 146,132 394 2,289 3,699,614 May-12 1,238,733 1,163 11,540 4,925,644 Jun-12 1,245,041 1,048 16,769 6,152,868 Jul-12 986,472 714 12,529 7,126,097 Aug-12 1,245,260 93 14,038 8,357,226 Sep-12 1,300,153 982 13,221 9,643,176 Oct-12 1,624,167 691 15,285 11,251,367 Nov-12 165,866 72,417 4,895 11,339,921 Dec-12 379,205 470,886 5,839 11,242,401 Jan-13 496,560 209,334 7,976 11,521,651 Feb-13 1,765,296 858 19,372 13,266,717 Mar-13 667,603 554,597 7,594 13,372,129 Apr-13 438,717 254,734 6,315 13,549,797 May-13 509,694 12,769 7,680 14,039,042 Jun-13 615,458 1,274 11,185 14,642,041 Jul-13 468,599 822 12,118 15,097,700 Aug-13 499,748 3,392 11,766 15,582,290 Sep-13 306,323 16,743 9,074 15,862,796 Oct-13 530,289 27,585 10,287 16,355,213 Nov-13 9,608 902,874 214 15,461,733 Dec-13 5 1,156,534 61 14,305,143 Jan-14 261,325 127,655 7,352 14,431,461 Feb-14 4,143 517,884 534 13,917,186 Mar-14 1 766,800 - 13,150,387 Apr-14 97,548 190,563 3,671 13,053,701 May-14 64,435 388,647 1,597 12,727,892 Jun-14 509,445 502,790 7,444 12,727,103 Jul-14 687,386 108,786 11,165 13,294,538 Aug-24 728,130 219 12,423 14,010,026 Sep-24 537,858 4,705 11,712 14,531,467 Oct-14 155,673 189,157 4,477 14,493,506 Nov-14 66,645 291,368 2,126 14,266,657 Dec-14 32,716 380,170 1,897 13,917,306 Jan-15 - 1,104,457 76 12,812,773 Feb-15 - 971,590 288 11,840,895 Mar-15 11,253 719,045 855 11,132,248 Apr-15 99,648 106,458 3,242 11,122,196 May-15 416,773 4,772 10,000 11,524,197 Jun-15 460,797 2,811 9,972 11,972,211 Jul-15 805,820 403 12,120 12,765,508 Aug-15 817,781 527 12,521 13,570,241 Sep-15 590,046 179 12,001 14,148,107 Oct-15 532,624 13,990 11,159 14,655,582 Nov-15 286,336 283,937 5,958 14,652,023 Dec-15 267,908 210,747 5,989 14,703,195 Jan-16 192,325 235,414 5,523 14,654,583 Feb-16 242,504 167,856 5,852 14,723,379 Mar-16 193,549 165,556 3,621 14,747,751 Apr-16 887,796 12,785 9,970 15,612,792 May-16 807,600 66,640 9,628 16,344,124 Jun-16 815,655 499,321 9,553 16,650,905 Jul-16 356,887 136,370 7,744 16,863,678 Aug-16 442,736 134,541 9,013 17,162,860 Sep-16 310,570 351,469 4,015 17,117,946 Oct-16 4,550 454,156 777 16,667,563 Nov-16 189,606 544,376 633 16,312,160 Dec-16 173,058 849,832 3,891 15,631,495 Jan-17 106,318 1,641,030 1,766 14,095,017 Feb-17 63,362 1,043,257 531 13,114,591 Mar-17 107,373 1,270,218 477 11,951,269 Apr-17 261,104 423,606 3,754 11,785,013 May-17 668,488 59,640 8,760 12,385,101 Cook Inlet Natural Gas Storage Alaska Storage Monthly Storage Activity (all volumes reported are at month end unless noted otherwise) CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 30 Month Injections - Mcf Withdrawals - Mcf Compressor Fuel &Losses Total Gas in Storage - Mcf Cook Inlet Natural Gas Storage Alaska Storage Monthly Storage Activity (all volumes reported are at month end unless noted otherwise) Jun-17 907,436 28,511 10,091 13,253,935 Jul-17 966,690 32,446 10,986 14,177,193 Aug-17 1,115,740 10,710 12,360 15,269,863 Sep-17 331,812 82,700 6,863 15,512,112 Oct-17 225,352 348,377 4,436 15,384,651 Nov-17 193,092 578,271 4,467 14,995,005 Dec-17 457,089 435,777 6,239 15,010,078 Jan-18 89,990 1,012,254 2,006 14,085,808 Feb-18 193,987 857,195 2,935 13,419,665 Mar-18 452,229 234,220 6,758 13,630,916 Apr-18 191,077 392,365 3,365 13,426,263 May-18 161,360 471,695 1,756 13,114,172 Jun-18 819,837 110,434 10,077 13,813,498 Jul-18 919,858 57,356 10,987 14,665,013 Aug-18 949,984 65,379 12,216 15,537,402 Sep-18 614,287 62,221 10,945 16,078,523 Oct-18 698,059 375,131 9,307 16,392,144 Nov-18 677,199 181,701 11,733 16,875,909 Dec-18 321,282 484,572 5,862 16,706,757 Jan-19 65,794 1,644,880 922 15,126,749 Feb-19 143 1,401,125 87 13,725,680 Mar-19 359,739 331,718 5,094 13,748,607 Apr-19 251,075 585,698 5,985 13,407,999 May-19 179,824 234,173 4,405 13,349,245 Jun-19 664,084 90,483 9,957 13,912,889 Jul-19 927,816 120,912 11,955 14,707,838 Aug-19 622,444 88,095 10,849 15,231,338 Sep-19 284,486 262,203 6,568 15,247,053 Oct-19 391,582 514,064 7,921 15,116,650 Nov-19 466,551 409,699 8,517 15,164,985 Dec-19 687,453 500,799 10,257 15,341,382 Jan-20 33,175 1,937,845 787 13,435,925 Feb-20 215,774 1,030,021 2,675 12,619,003 Mar-20 203,541 858,156 3,102 11,961,286 Apr-20 202,521 497,341 4,699 11,661,767 May-20 338,538 170,141 6,793 11,823,371 Jun-20 1,193,238 58,213 10,952 12,947,444 Jul-20 1,356,896 82,724 14,766 14,206,850 Aug-20 1,561,784 15,287 21,585 15,731,762 Sep-20 587,912 15,493 9,260 16,294,921 Oct-20 367,037 363,622 7,488 16,290,848 Nov-20 182,989 660,824 4,962 15,808,051 Dec-20 558,901 327,351 9,271 16,030,330 Jan-21 381,681 595,917 6,988 15,809,106 Feb-21 270,840 633,374 4,477 15,442,095 Mar-21 32,319 816,414 1,088 14,656,912 Apr-21 250,078 958,308 6,120 13,942,562 May-21 591,683 61,728 10,883 14,461,634 Jun-21 981,660 44,752 12,306 15,386,236 Jul-21 1,017,570 113,951 13,012 16,276,843 Aug-21 740,130 196,225 12,510 16,808,238 Sep-21 346,001 389,600 7,205 16,757,434 Oct-21 62,726 541,078 2,581 16,276,501 Nov-21 271,271 1,414,990 3,061 15,129,721 Dec-21 355,444 787,346 4,747 14,693,072 Jan-22 267,601 1,066,583 3,553 13,890,537 Feb-22 456,020 485,243 6,729 13,854,585 Mar-22 291,686 362,218 5,283 13,778,770 Apr-22 143,328 245,781 4,490 13,671,827 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 31 Month Injections - Mcf Withdrawals - Mcf Compressor Fuel & Losses -Mcf Total Gas in Storage - Mcf May-22 802,773 138,598 11,483 14,324,519 Jun-22 1,326,806 24,269 14,643 15,612,413 Jul-22 1,322,577 31,570 17,348 16,886,072 Aug-22 770,367 46,860 12,367 17,597,212 Sep-22 241,173 206,027 7,890 17,624,469 Oct-22 196,753 520,661 5,421 17,295,139 Nov-22 145,814 843,846 3,982 16,593,124 Dec-22 347,410 764,252 6,364 16,169,918 Jan-23 817,233 148,539 11,592 16,827,020 Feb-23 136,157 555,430 3,828 16,403,919 Mar-23 69,886 722,788 2,918 15,748,099 Apr-23 27,738 1,296,361 1,226 14,478,250 May-23 318,334 368,017 7,698 14,420,869 Jun-23 820,659 88,824 10,798 15,141,906 Jul-23 1,051,707 186,058 12,301 15,995,254 Aug-23 914,771 94,816 11,898 16,803,311 Sep-23 270,994 248,383 8,376 16,817,546 Oct-23 159,593 1,137,013 4,639 15,835,487 Nov-23 291,211 686,604 5,898 15,434,196 Dec-23 172,087 805,887 3,049 14,797,347 Jan-24 210,008 1,208,971 2,957 13,795,427 Feb-24 389,503 586,567 5,957 13,592,406 Mar-24 457,012 312,385 6,894 13,730,139 Apr-24 173,633 529,514 6,289 13,367,969 May-25 532,378 137,058 9,774 13,753,515 Jun-25 1,111,643 71,491 11,887 14,781,780 Jul-25 1,192,026 37,247 12,752 15,923,806 Aug-25 842,657 32,611 12,289 16,721,563 24-Sep 243,370 89,392 6,058 16,869,483 24-Oct 66,658 943,053 2,637 15,990,450 24-Nov 192,375 935,910 4,012 15,242,903 24-Dec 174,642 568,926 3,747 14,844,873 25-Jan 345,315 584,141 3,796 14,602,249 25-Feb 176,983 561,125 2,748 14,215,360 25-Mar 583,107 167,977 5,606 14,624,884 25-Apr 25,241 664,725 1,004 13,984,576 Cook Inlet Natural Gas Storage Alaska Storage Monthly Storage Activity (all volumes reported are at month end unless noted otherwise) Total Inventory as of April 14, 2025: 14,137,644 mmcf CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 32 Table 2 – September 2024 Wellhead Shut-in Pressure Data Table 3 – April 2025 Wellhead Shut-in Pressure Data Well Name Weight Factor* (Storage Pore-feet = (Por.*net MD*(1-Sw))9/10/2024 9/11/2024 9/12/2024 9/13/2024 9/14/2024 9/15/2024 9/16/2024 CLU S-1 70.235 1696.5 1693.1 1690.9 1688.5 1687.7 1686.1 1684.5 CLU S-2 47.696 1693.3 1689.3 1687.7 1686.7 1685.3 1684.0 1683.7 CLU S-3 24.024 1679.7 1675.7 1673.3 1671.7 1670.1 1669.3 1667.7 CLU S-4 97.011 1689.3 1685.5 1682.9 1680.5 1678.1 1676.5 1674.1 CLU S-5 93.155 1681.3 1677.7 1675.3 1673.7 1672.1 1671.3 1669.7 332.121 Weighted Avg. WHP (WAP)1688.5 1684.8 1682.5 1680.5 1678.9 1677.6 1676.0 Arithmetic Average 1688.0 1684.3 1682.0 1680.2 1678.7 1677.4 1675.9 Percentage Difference 0.026%0.029%0.026%0.019%0.014%0.011%0.002% Day 2 vs. Day 1 Day 3 vs. Day 2 Day 4 vs. Day 3 Day 5 vs. Day 4 Day 6 vs. Day 5 Day 7 vs. Day 6 WAP Change -3.7 -2.30 -1.92 -1.64 -1.27 -1.65 Well Name Day 2 vs. Day 1 Day 3 vs. Day 2 Day 4 vs. Day 3 Day 5 vs. Day 4 Day 6 vs. Day 5 Day 7 vs. Day 6 CLU S-1 -3.4 -2.2 -2.4 -0.8 -1.6 -1.6 CLU S-2 -4.0 -1.6 -1 -1.4 -1.3 -0.3 CLU S-3 -4 -2.4 -1.6 -1.6 -0.8 -1.6 CLU S-4 -3.8 -2.6 -2.4 -2.4 -1.6 -2.4 CLU S-5 -3.6 -2.4 -1.6 -1.6 -0.8 -1.6 Wellhead Shut-in Pressures (psig) and Dates NOTE: Red text reflects estimated wellhead pressure due to standing fluid in the wellbore above the top of the perforations. Readings in black text are from pressure transmitter readings obtained from the tree cap, upstream of the choke. Weighted Average Pressure (Day-to-Day Change) Individual Well Pressure (Day-to-Day Change) Weight Factor* - based on Ray Eastwood Log Model Well Name Weight Factor* (Storage Pore-feet = (Por.*net MD*(1-Sw))4/15/2025 4/162025 4/17/2025 4/18/2025 4/19/2025 4/20/2025 4/21/2025 CLU S-1 70.235 1364.9 1373.7 1379.6 1384.1 1387.3 1389.7 1392.9 CLU S-2 47.696 1378.5 1386.5 1391.3 1394.4 1396.9 1398.5 1400.2 CLU S-3 24.024 1445.8 1449.0 1450.6 1451.4 1452.2 1452.2 1452.2 CLU S-4 97.011 1442.5 1444.2 1445.8 1445.9 1446.6 1446.6 1446.6 CLU S-5 93.155 1460.0 1457.0 1455.8 1453.4 1451.8 1450.4 1449.4 CLU S-6 N/A 1547.5 1536.3 1533.1 1531.6 1531.5 1530.8 1531.4 CLU S-7 N/A 1361.5 1370.5 1377.7 1382.5 1386.5 1389.7 1392.1 332.121 1422.0 1424.9 1427.1 1427.9 1428.8 1429.1 1429.8 1428.7 1431.0 1433.4 1434.8 1436.1 1436.8 1437.8 Percentage Difference -0.466%-0.427%-0.441%-0.478%-0.513%-0.540%-0.564% Day 2 vs. Day 1 Day 3 vs. Day 2 Day 4 vs. Day 3 Day 5 vs. Day 4 Day 6 vs. Day 5 Day 7 vs. Day 6 WAP Change 2.9 2.18 0.81 0.85 0.34 0.64 2.4 2.4 1.3 1.4 0.7 1.0 Well Name Day 2 vs. Day 1 Day 3 vs. Day 2 Day 4 vs. Day 3 Day 5 vs. Day 4 Day 6 vs. Day 5 Day 7 vs. Day 6 CLU S-1 8.8 5.9 4.5 3.2 2.4 3.2 CLU S-2 8.0 4.8 3.1 2.5 1.6 1.7 CLU S-3 3.2 1.6 0.8 0.8 0 0 CLU S-4 1.7 1.6 0.1 0.7 0 0 CLU S-5 -3 -1.2 -2.4 -1.6 -1.4 -1 CLU S-6 -11.2 -3.2 -1.5 -0.1 -0.7 0.6 CLU S-7 9 7.2 4.8 4 3.2 2.4 Wellhead Shut-in Pressures (psig) and Dates NOTE: Red text reflects estimated wellhead pressure due to standing fluid in the wellbore above the top of the perforations. Readings in black text are from pressure transmitter readings obtained from the tree cap, upstream of the choke. Weighted Average Pressure (Day-to-Day Change) Individual Well Pressure (Day-to-Day Change) Weight Factor* - based on Ray Eastwood Log Model Weighted Avg. WHP (WAP) - Orig. 5 Wells Arithmetic Average - All 7 Wells Arithmetic Avg. Press. Change CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 33 Table 4 – Shut-in Reservoir Pressure History and Gas-in-Place Summary Wellhead Pressure - psig.Bottom Hole Pressure - psia Z - Factor BHP/Z - psia Total Gas-in Place - mmscf Date 0 0 10/28/2000 1950 2206 0.8465 2606 26,500 Date Weighted Avg. Wellhead Pressure - psig. Calculated Bottom Hole Pressure - psia Z - Factor BHP/Z - psia Total Gas-in Place - mmscf 11/8/2012 1269.9 1434.9 0.8719 1645.7 11,223.715 4/15/2013 1344.4 1522.35 0.8668 1756.3 13,106.887 11/4/2013 1580.7 1798.1 0.8508 2113.4 16,339.046 4/8/2014 1320.6 1497.7 0.8662 1729.0 13,147.315 10/31/2014 1465.1 1662.3 0.858 1937.4 14,493.502 4/8/2015 1159.6 1315.8 0.877 1500.3 11,123.289 11/8/2015 1499.4 1701.4 0.856 1987.6 14,668.761 3/27/2016 1473.3 1671.6 0.857 1950.5 14,634.101 10/30/2016 1582.4 1792.2 0.853 2100.0 16,667.452 4/10/2017 1212.0 1371.9 0.875 1567.9 11,908.476 10/9/2017 1559.8 1766.5 0.855 2067.3 15,523.158 5/8/2018 1376.1 1557.8 0.864 1803.6 13,424.899 10/8/2018 1621.9 1837.1 0.8517 2157.0 16,081.391 4/22/2019 1370.2 1551.1 0.8647 1793.8 13,587.409 10/28/2019 1499.6 1698.9 0.854 1989.3 15,000.096 4/13/2020 1225.6 1390.2 0.872 1595.0 11,822.427 9/8/2020 1617.1 1814.9 0.852 2130.2 15,743.463 4/19/2021 1383.0 1565.6 0.864 1812.0 13,877.999 9/20/2021 1672.0 1894.0 0.850 2228.2 17,042.781 4/18/2022 1387.6 1570.8 0.864 1818.7 13,667.164 9/19/2022 1709.2 1936.3 0.848 2283.4 17,714.717 4/17/2023 1481.3 1679.7 0.856 1963.2 15,171.311 9/18/2023 1662.9 1883.7 0.850 2216.1 16,925.613 4/15/2024 1366.6 1547.0 0.865 1788.4 13,498.572 9/16/2024 1676.0 1901.4 0.847 2244.8 16,906.401 4/21/2025 1437.8 1630.2 0.858 1900.0 14,137.644 Gas Gravity:0.56 N2 Conc.:0.3% CO2 Conc.:0.3% Reservoir Temp. (deg. F):105 Datum Depth TVD (ft.):4950 Avg. Measured Depth (ft.):9706 Shut-in Reservoir Pressure History and Gas-in-Place Summary - (No Adjustment for Additional Native Gas) Original (Discovery) Reservoir Conditions Storage Operating Conditions CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 34 Table 5– Shut-in Reservoir Pressure History and Gas-in-Place Summary (Adjusted Inventory) Wellhead Pressure - psig.Bottom Hole Pressure - psia Z - Factor BHP/Z - psia Initial Total Gas-in Place - MMcf Date 0 0 10/28/2000 1950 2206 0.8465 2606 41,000 Adjusted Total Gas-in Place - Est. 14.5 Bcf Found Gas 0 0 10/28/2000 1950 2206 0.8465 2606 41,000.000 11/8/2012 1269.9 1434.9 0.8719 1645.7 25,723.715 4/15/2013 1344.4 1522.35 0.8668 1756.3 27,606.887 11/4/2013 1580.7 1798.1 0.8508 2113.4 30,839.046 4/8/2014 1320.6 1497.7 0.8662 1729.0 27,647.315 10/31/2014 1465.1 1662.3 0.858 1937.4 28,993.502 4/8/2015 1159.6 1315.8 0.877 1500.3 25,623.289 11/8/2015 1499.4 1701.4 0.856 1987.6 29,168.761 3/27/2016 1473.3 1671.6 0.857 1950.5 29,134.101 10/30/2016 1582.4 1792.2 0.853 2100.0 31,167.452 4/3/2017 1212.0 1371.9 0.875 1567.9 26,408.476 10/9/2017 1559.8 1766.5 0.855 2067.3 30,123.158 5/8/2018 1376.1 1557.8 0.864 1803.6 27,924.899 10/8/2018 1621.9 1837.1 0.8517 2157.0 30,581.391 4/22/2019 1370.2 1551.1 0.8647 1793.8 28,087.409 10/28/2019 1499.6 1698.9 0.854 1989.3 29,500.096 4/13/2020 1225.6 1390.2 0.872 1595.0 26,322.427 9/8/2020 1617.1 1814.9 0.852 2130.2 30,243.463 4/19/2021 1383.0 1565.6 0.864 1812.0 28,377.999 9/20/2021 1672.0 1894.0 0.850 2228.2 31,542.781 4/18/2022 1387.6 1570.8 0.864 1818.7 28,167.164 9/19/2022 1709.2 1936.3 0.848 2283.4 32,214.717 4/17/2023 1481.3 1679.7 0.856 1963.2 29,671.311 9/18/2023 1662.9 1883.7 0.850 2216.1 31,425.613 4/15/2024 1366.6 1547.0 0.865 1788.4 27,998.572 9/16/2024 1676 1901.4 0.847 2244.8 31,406.401 4/21/2025 1437.8 1630.2 0.858 1900.0 28,637.644 Gas Gravity:0.56 N2 Conc.:0.3% CO2 Conc.:0.3% Reservoir Temp. (deg. F):105 Datum Depth TVD (ft.):4950 Avg. Measured Depth (ft.):9706 Original (Discovery) Reservoir Conditions Shut-in Reservoir Pressure History and Gas-in-Place Summary - (Adjusted to Account for Additional Native Gas) CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 35 Figure 1 – CLU S-2 and S-3 Wellhead Pressure versus Inventory CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 36 Figure 2 – September 2024 Wellhead Shut-in Pressures Figure 3– April 2025 Wellhead Shut-in Pressures CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 37 Figure 4 – Material Balance Plot (Unadjusted) CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 38 Figure 5 – Material Balance Plot (Adjusted) Spring 2024 Shut-in Pressure = 1788.4 psia CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 39 Figure 6 - Historical and Computed Pressures vs. Rate (Found Gas at 14.5 Bcf) CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 40 Figure 7 - Estimated Gas Transfer to/from Original Reservoir CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 41 Figure 8 - Historical and Computed Pressures vs. Rate (Found Gas at 24 Bcf) CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 42 Figure 9 – Annulus Pressure of CLU Storage – 1 Figure 10 – Annulus Pressure of CLU Storage – 2 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 43 Figure 11 – Annulus Pressure of CLU Storage – 3 Figure 12 – Annulus Pressure of CLU Storage – 4 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 44 Figure 13 – Annulus Pressure of CLU Storage – 5 Figure 14 – Annulus Pressure of CLU Storage – 6 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 45 Figure 15 – Annulus Pressure of CLU Storage – 7 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 46 Figure 16 – Annulus Pressure of Marathon CLU 1RD Figure 17 – Annulus Pressure of Marathon CLU 3 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 47 Figure 18 – Annulus Pressure of Marathon CLU 4 Figure 19 – Annulus Pressure of Marathon CLU 05RD CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 48 Figure 20 – Annulus Pressure of Marathon CLU 6 Figure 219 – Annulus Pressure of Marathon CLU 7 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 49 Future 22 – Annulus Pressure of Marathon CLU 8 Figure 23 – Annulus Pressure of Marathon CLU 9 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 50 Figure 24 – Annulus Pressure of Marathon CLU 10RD2 Figure 25 – Annulus Pressure of Marathon CLU 11 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 51 Figure 26 – Annulus Pressure of Marathon CLU 12 Figure 27– Annulus Pressure of Marathon CLU 13 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 52 Figure 28– Annulus Pressure of Marathon CLU 14 Figure 29– Annulus Pressure of Marathon CLU 15 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 53 Figure 30– Annulus Pressure of Marathon CLU 16 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 54 Figure 31 – Historical Monthly Production CLU – 01RD Beluga Figure 32 – Historical Monthly Production CLU – 01RD Upper Tyonek CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 55 Figure 33 – Historical Monthly Production CLU – 05RD2 Beluga Figure 34 – Historical Monthly Production CLU – 05RD2 Tyonek D Gas CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 56 Figure 35 – Historical Monthly Production CLU – 7 Beluga Figure 36 – Historical Monthly Production CLU – 8 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 57 Figure 37 – Historical Monthly Production CLU – 9 Figure 38 – Historical Monthly Production CLU – 10RD2 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 58 Figure 39 – Historical Monthly Production CLU – 13 Figure 40 – Historical Monthly Production CLU – 14 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 59 Figure 41 – Historical Monthly Production CLU – 15 Figure 42 – Historical Monthly Production CLU – 16 CINGSA Material Balance Report to the AOGCC May 15, 2025 Page 60