• Reserves at December 31, 2022 - audited by InSite Petroleum Consultants Ltd:
o 3P reserves 24.4 million boe
o 2P Reserves 20.5 million boe
o 1P Reserves 16.1 million boe
o PDP Reserves 7.0 million boe
• Proved Developed Producing, (“PDP”) reserves increased 37% to 7.0 million boe (net of royalties), 4% for our
Total Proved (“TP”) reserves, and 1% for our Total Proved plus Probable (“P+P”) reserves year over year.
• In 2022, Calima’s successful development capital program achieved a capital efficiency of $14,200 per boe/d
for the 2022 calendar year.
• The Company achieved a reserve replacement ratio of 192%, 145% and 160% of our PDP, TP, and P+P reserves
respectively, while growing annual production by 23%.
• PDP, TP and TPP reserve life index ("RLI") of 6.3 years, 11.9 years and 14.7 years, respectively, reflects our
long-life oil weighted assets with a deep inventory, providing for long-term sustainable and profitable growth.
• Our PDP Finding, Development and Acquisition (“FD&A”) cost of A$11.51 per boe generated a recycle ratio
of 4.2x on an unhedged basis and reflects strong operational execution by our team in 2022. Our TP and TPP
recycle ratios increased 36% and 57%, respectively as compared to 2021. The Company’s 3-year average
PDP FD&A cost is A$14.23/boe. There were no production acquisitions or sales in 2022.
• Continuing to focus on maintaining low levels of abandonment liability provides significant corporate
flexibility; in 2022 this was continued via the successful abandonment of 10 gross wells. Our industryleading liability management ratio ("LMR") at year-end 2022 was 6.23
• The Company drilled 16 wells in 2022 of which 8 were proven undeveloped locations (PUD’s) transforming
location value into PDP cash flow generating assets which have materially greater market value.
• The focused asset bases of Brooks and Thorsby coupled with high graded infill drilling and prudent production
management allowed Blackspur to maintain TP and P+P reserves steady after production of 1.43 million boe
for the 2022 year.
Calima Energy Limited is pleased to present the results
and in-depth analysis of its independent reserve report for its Thorsby and Brooks assets for Calima’s wholly owned
subsidiary Blackspur Oil Corp. (“Blackspur”). as at 31 December 2022. The evaluation encompassed 100% of
Brooks and Thorsby reserves and was completed by independent reserve evaluator InSite Petroleum Consultants
Ltd. (“InSite”) in accordance with the Society of Petroleum Engineers’ Petroleum Resources Management System
(SPE-PRMS). 2022 represents the Company’s 10th year of successful reserves development.
In 2022, the Company invested A$49.7 million to drill 16 wells and expand the waterflood in the Lower Mannville
J2J oil pool ("J2J pool"), upgrade facilities in the Brooks area, complete well maintenance programs on producing
assets, perform mandated well abandonments, and purchase land and seismic. Corporate production increased
by approximately 23% year-over-year, averaging 3,921 boe/d in 2022. The commencement of 2023 saw the full
impact on production from the 5 well Q4 2022 development program with the Company’s average production for
2023 currently averaging ~4,500 boe/d. In Q1 2023, the Company successfully drilled and completed two
additional wells at Brooks (Pisces #8 and #9); the impact of these wells will be realised primarily in the Q2 2023 corporate production. 2022 year-end reserves reflect the quality and sustainability of our low decline base
production, complemented by the drilling of new wells throughout the year. In 2022, the Company focussed on
reducing financial risk and improving the long-term sustainability of our assets.
Our 2022 year-end reserves continue to be strong across all categories enhanced by our diverse inventory. Most
notably the large inventory and oil in place in both the Brooks and Thorsby assets is a tremendous resource
supporting multi-year growth potential to complement our high netback conventional asset base. We have a
significant inventory of locations providing the Company with years of profitable and sustainable growth in cash
flow, reserves, and production.
The development plan in the December 31, 2022 Reserve Report consists of 54 (gross) wells, 48 PUD’s and 6
probable locations, to be drilled over 5 years. The schedule and breakdown in each reserve category is summarised
in the table below. The development plan is scheduled for proved and probable well locations to be drilled within
a 5-year period. All future development capital (“FDC”) for the TP and P+P reserve categories is included and
reflects an increase year over year due to inflation.
In the 31 December 2022 year-end InSite report, the 2023 development program includes 10 wells to be drilled
including, 2 Thorsby Sparky wells, 4 Brooks Sunburst wells, and 4 Brooks Glauconitic wells (2 are now drilled as
part of the Pisces campaign). On a net well count for the proved reserve category, Blackspur has a ~95% interest
in the proved undeveloped wells in the 2023 development plan.
At 31 December 2022, The Company held the rights to ~117,000 net acres within the Brooks and Thorsby areas
and the Company operates 90 producing wells. The year-end reserve development schedule encompasses development of a modest portion of the total acreage position that Blackspur holds. Based on the existing
leasehold position, including the acreage associated with the existing producing wells, Blackspur estimates a total
of approximately 220 net wells will be required to develop the entire reserve position. Significant undeveloped
Brooks and Thorsby acreage has no reserves booked currently, representing material upside to the existing report.
The total 2023 development schedule corresponds to 54 future wells (50.75 net), or 23% of the wells necessary to
develop the entire acreage position. Blackspur continues to focus on abandoning and reclaiming our nonproducing assets and in 2023 will spend a minimum of A$780,000. This spending achieves a reserve valuation that
is in a much stronger and resilient position on a value per barrel basis compared to companies with high ADR
liabilities. Management estimates that total undiscounted and uninflated existing ADR is A$23.6 million (A$8.6
million NPV10 BT, with costs inflated at 2%/yr thereafter). This includes all ADR associated with both active and
inactive wells, pipelines, and facilities. Consistent with the 2021 year-end evaluation, InSite’s 2022 Reserve Report
incorporates full corporate abandonment, decommissioning, and reclamation costs ("ADR") in the PDP category.
Based on public information, the Company stands out among its industry peers as being within the top tier of
Alberta oil and gas operators for its industry-leading liability management ratio ("LMR") of 6.23. Less than 10% of
our PDP net present value is impaired by ADR.
The Brooks asset has an established core land position of ~69,000 net acres and significant infrastructure creating
a foundation for growth and expansion with nearly year-round access. The Brooks reservoirs contain a low CO2
content at ~2%, and the Company’s multi-well pad drilling reduces the environmental footprint. Blackspur has an
extensive network of existing infrastructure including oil treating facilities and water disposal across the entire
Brooks area that can process up to 7,200 bbl/d oil, 25,000 barrels per day of water and 10.8 MMcf/d cumulatively
across all of its various facilities. With over 75 wells drilled to date, the Brooks asset has averaged net daily
production of ~3,500 boe/d from 1 Jan 2023 to date.
The Sunburst Formation does not require hydraulic fracture stimulation and can be developed at low cost (~C$1.
5MM per well) delivering attractive rates of return and short payouts (~90% and ~12 - 14 months respectively) at
US$70 WTI and standard type curves. The Company drilled and placed on production 8 Sunburst (Gemini) wells
The Glauconitic Formation is a shallower formation than Calima’s core Sunburst conventional play and requires
hydraulic fracture stimulation. The combination of the shallow target depth and short tie-in, results in an all-in
cost for each well of C$2-$3M, depending on horizontal length and fracture intensity. The Glauconitic wells have
proven to be very impactful to corporate production and reserve bookings in 2022. The Company drilled and
placed on production 7 Glauconitic (Pisces) wells in 2022 and has drilled 2 additional wells in 2023 which came on
production in March 2023. ~20% of the wells drilled in 2022 have already paid out their initial capital investment.
Future growth from the Brooks assets will come from the 138 net locations that have been identified. These
locations include 28 booked (24.75 net) PUDs and 2 (2 net) probable locations. Only 19% of the identified locations
have been booked for the purposes of InSite’s Reserve Report. The 2023 Brooks drilling program will be focussed
on Sunburst and Glauconitic drilling. At current oil prices the Company is able to continue drilling a risk adjusted
balanced mix of Sunburst and Glauconitic Formation horizontal locations to prudently grown production and
reserves. Additional reserves are also expected to be realised through implementation of enhanced oil recovery
projects and specifically the full water-flood development of the Countess J2J Sunburst pool.
In January 2020, the Company initiated a waterflood in the
Countess J2J Pool which has been showing positive results.
InSite has recognized 1P and 2P waterflood reserves
associated with this waterflood. Waterflood operations
require upfront capital and take time before field
performance improves and these benefits start to be
realized. Waterflood assets provide a stable, low decline
production base generating strong cash flows and reserves
over the long term.
The Countess Sunburst J2J Pool at Brooks (“the Pool”) was
discovered in 2003 and initially developed using vertical
wells. Horizontal drilling was introduced to the Pool by the
Company in 2014 which improved production rates and primary recoveries with strategically placed horizontal
well legs throughout the reservoir. In Q1 2020 a pilot waterflood was initiated and an oil battery contructed.
Based on the initial successful results of the pilot waterflood the Company continued the project in 2022 with the
addition of one water injector and securing additionalsource water to allow a continued ramp up of in the voidage
replacement. As well, a water tracer study was initiated to fine tune and better understand water movements
throughout the pool and facilitate continued optimization.
The Company is pleased to note that the initial stage of the Countess J2J waterflood has begun showing positive
response in the producing wells via increased oil and total fluid rates, thus facilitating increasing pumping speeds
on most producing wells. InSite continues to recognize 1P, 2P, and 3P waterflood reserves for the Pool. Further
waterflood expansion would include additional water injectors to continue increasing the quantum and areal
extent of water being injected in the Pool and increase reservoir pressure. This is expected to increase the
waterflood response in the Pool, resulting in increased cash flow, PDP reserves, shallower declines, and continued
increases in oil production.
Ultimate primary recovery factor for the Pool before any waterflood implementation is estimated at 14% of the
oil in place, and the current recovery factor, to date from the existing wells is estimated at 12%. This is inclusive
of the benefits of the waterflood. Analogous Sunburst Formation pools under waterflood in the area, have
achieved recovery factors of 25% or higher. Every 1% increase in recovery factor of the oil in place in the J2J Pool,
results in greater than 100mbbl of incremental recoverable reserves for the Company. Approximately 2% of the
potential increase in recoverable reserves in the Countless J2J Pool have been included in the Reserve Report.
There is no change to the fundamentals of the undeveloped wells and
InSite has made no material changes to their assumptions on future
undeveloped well production performance. The InSite reports
• In 2022 15 wells were drilled with 8 conventional Sunburst
horizontal play type and 7 Glauconitic stimulated horizontal wells.
• In 2023 four Sunburst wells and four Glauconitic horizontal wells
are planned in the reserve report.
• 28 PUDs (24.75 net) and 2 probable 100% locations
• 8 PUD to PDP conversions in 2022
• Reserves of: 1P – 8.4 mmboe, 2P – 10.2 mmboe, 3P – 12.2 mmboe
Development and Upside
Thorsby has a large inventory with 70 Sparky Formation and 12 Nisku Formation wells identified, including 20 PUD
and 4 probable Sparky locations. The Company’s existing Sparky Formation wells are characterised by current low
decline rates expected averaging ~17% per year over the next 2 years. Whilst the Thorsby area has the potential
for Duvernay and Nisku, these intervals have not been incorporated into the Reserve Report.
The Company’s Thorsby position provides a consolidated land base that can be efficiently developed through a
network of multi-well pads, all of which have nearly year-round access. The contiguous land base also contributes
to lower operating costs through greater logistical efficiencies. The Company’s facilities currently have oil
processing capacity of up to 1,450 bbl/d oil (subject to emulsion water cut volumes at the battery).
One step-out well (Leo #4) (0.5 net) was drilled and completed in the prospective North Thorsby area in 2022.
The Company continues to successfully optimise the drilling and
completion techniques and InSite’s development plan utilises a mix of
extended reach and 1 mile horizontal wells with higher intensity fractures,
compared to the early-stage wells. This reduces gross well locations while
the improving future undeveloped well production performance and
reserves. There was minimal year over year changes to the proven
undeveloped reserves apart from the increased capital costs reflecting
current inflationary trends.
The Company may drill 2 development wells in Thorsby in 2023. Each are
being drilled into the existing Sparky Formation oil pool, which was
delineated by both existing Sparky wells and 3D seismic. The well length
and frac intensity will be similar to the 2021 Leo drilling program.
• 3P production profile over a prolific reserve lifecycle
• 20 PUD’s and 4 probable 100% locations
• Reserves of: 1P - 7.6 mmboe, 2P - 10.2 mmboe, 3P - 12.2 mmboe
A proved, probable and possible (3P) reserve evaluation category was evaluated for all wells and locations
booked at December 31, 2022 totalling 24.4 million boe’s. 3P EURs are determined using volumetric calculation
as well as production performance / type curve reserve estimates where applicable. The 2022 Possible reserves
are 3.9 million boe, net of royalties. 3P reserves were split as follows: Brooks 3P reserves of 12.2 million boe and
Thorsby 3P reserves of 12.2 million boe.
This release has been approved by the Board.
• The majority of the reserve estimates were prepared using deterministic methods that do not provide a
mathematically derived quantitative measure of probability. In principle, there should be no difference
between estimates prepared using probabilistic or deterministic methods.
• The oil price used for all reserves analysis in this report is stated in the table at the end of this release. The
reserves are disclosed net to the point of sale (reference point) and are reported net of lease fuel.
• The Company is the operator for materially all its producing wells and all the future drills.
• Operating costs for developed producing wells are based on actual costs incurred through YE2022. Operating
costs for future wells and years are based on the same data and estimated following a review of operating
statements, operating budgets, as well as review of public records where available. Cross checks were
conducted between the revenue statements and land data to ensure they agreed. Fixed and variable costs
have been assigned to the Company’s active assets with remaining reserves. Operating costs associated with
inactive assets as well as producing wells with no reserves assigned have been entered as separate entities at
the property level.
• In conducting InSite’s reserve analysis, proved, probable and possible reserve volumes were determined by
volumetric, material balance, and production decline curve methods. The volumetric reserves were
determined by reviewing all well logs, core, and geological data. Recovery factors were assigned after
analyzing the performance of similar wells in the area. Historical well production was reviewed to determine
reserves calculated by production decline curve analysis. The order of preference in choosing the
methodology to be used was primarily production decline curve analysis or material balance where sufficient
data was available for such analysis with volumetrics being used where there was a lack of historical data.
• 100% of the proved producing reserves were calculated based on decline analysis, oil-cut analysis and other
performance/volumetric related prediction methods, compared to 45% (44% net) of the total proved reserves
and 40% (40% net) of the proved plus probable reserves, and 40% (40% net) of proved plus probable plus
possible reserves which used these methods. Volumetrics/simulation/analogy/type curve analyses were used
to calculate the remaining percentages of reserves in each category.
• The EUR assignments are largely influenced by the production performance of existing producing wells and
their associated volumetric recovery. In the case of undeveloped drilling locations, reserve assignments and
production profiles are based on analogy to the offsetting producers in the nearby vicinity and/or other
• The probable reserves contained in the report consist of two general types:
o Performance-related (i.e. Proved plus Probable Developed) reserves represent the best estimate
overall. Proved reserves are a more conservative estimate of the recovery from wells where Possible
reserves represent a more optimistic and lower probability estimate.
o Proved plus probable reserves can also include enhanced recovery reserves which are only partially
recognized under proved reserves. The “wedge” or difference between the Proved Developed and
Proved plus Probable Developed cases represents 25% (26% net) of the Company’s Probable reserves.
The “wedge” between Proved plus Probable Developed and Proved plus Probable plus Possible
Developed cases represents 37% (38% net) of the Company’s Possible reserves.
• Future horizontal step-out wells represent 73% (73% net) of the Company’s probable reserves.
• Future vertical step-out wells represent 1.7% (1.7% net) for the Company’s probable reserves.
The oil and gas reserve calculations and income projections upon which this report is based were determined
in accordance with generally accepted evaluation practices and evaluation process was consistent with prior
• Proposed future well locations are allocated a reserve category based on proximity to existing wells and
• Probable reserves were assigned such that there is a 50% probability that the assigned reserves could be
recovered, or more on an aggregated basis.
• Proved plus Probable plus Possible reserves were assigned such that there is a 10% probability that the
assigned reserves could be recovered, or more on an aggregated basis.
• The production and revenue forecasts contained in the 31 December 2022 evaluation include abandonment
and reclamation costs for each of the Company’s existing and proposed wells that were assigned reserves in
this report. These costs were determined using the Alberta Energy Regulator’s Directive 011 as a base. The
costs associated with abandonment, decommissioning, reclamation, and salvage of facilities, as well as
inactive assets, have been entered as separately.
• The five-year development plan used for this reserve report is detailed in Table 2 above and assumes a multi
rig program to develop a total of 54 gross well locations. The development plan assumes 2-6 wells per
standard development unit and approximately 128 - 160 acre spacing.
• Anticipated drilling, completion & tie-in well costs range from C$0.8 to C$4.5 million depending on whether
it’s a Sunburst, Glauconitic or Sparky well.
• The development plan assumes an initial estimate of 6-14 days respectively to drill new wells.
• Average royalties payable on future well locations that were allocated reserves in this report is ~16% over the
life of the wells. The land type and related royalties are either Crown or Freehold and the average royalty for
the PDP forecast for 2023 is 19%.
• Each year, for the purposes of estimating undeveloped reserves, a development schedule is generated which
must be appropriate and reasonable for the Company to execute on. This development plan is prepared in
consultation with InSite and takes into consideration market conditions and the Company’s operational
capacity, including financing and historical drilling activity. The plan must also conform to the various ASX and
SPE-PRMS requirements, the key points of which are:
o the development plan is executed over a 5-year period from the effective date.
o proved well locations must be drilled within 5 years of the date they were first certified as a reserve in
o The InSite evaluation has been prepared for the Company in accordance with reserves definitions,
standards and procedures contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook and
have been classified in accordance with the Society of Petroleum Engineers’ Petroleum Resources
Management System (SPE-PRMS) and reported in the most specific resource class in which the
prospective resource can be classified under 2018 SPE-PRMS. The reserves presented in the InSite
report are based on forecast prices and costs. The price forecast used for the reference price of oil based
on Cushing, Edmonton and Western Canadian Select benchmarks, as well as the netback prices for
natural gas for the major purchasers. All oil prices used in the evaluation have been adjusted from the
reference price for quality and transportation; gas prices have been adjusted for heating value. Please
note that the effects of any oil or gas hedging activities by the Company have not been included in this
report. The reserves are disclosed net to the reference point.
o In the context of belonging to a larger portfolio of properties and coupled with the principal of
aggregation of reserves, the total portfolio reserves estimate carries a higher degree of confidence than
the estimates for the individual properties.