WTI (Mar) $80.13 -$1.49, Brent (Mar) $86.13 -$2.06, Diff -$6.00 -57c, USNG (Feb) $3.25 -19c, UKNG (Feb) 141.25p -8.75p, TTF (Feb) €55.82 -€2.93

Oil price

Oil gave up the week’s gains after mixed data from the US panicked buyers although they were only PMI stats and the Euroland numbers actually beat the whisper. The inventory stats from the API were in line showing a build in crude and gasoline and a  draw in distillates.

The EIA STEO talked down US production growth very much in line with what I’m hearing from on the ground, 12m b/d or thereabouts won’t be smashed anytime soon especially with the rig count down 10 units last week…

IOG

IOG has provided a corporate update in advance of the Company’s full-year 2022 results, which are scheduled for release in March 2023. The information contained herein has not been audited and may be subject to further review.

Current and Planned Operations

Southwark

• At the A2 well, following analysis of the production logging tool data, the plan for the coming weeks is to isolate three of the six stimulated zones, add further perforations to two other zones and then re-test the well 
• The A1 well is to be located in the western part of the reservoir, where the proximity of its reservoir entry point to the Southwark discovery well (49/21-8A) may reduce uncertainties    
• A2 data is being used to inform the updated A1 programme, which includes hydraulic stimulation of five zones

Blythe & Elgood

• The Blythe H1 well is currently producing gas in the 16-21 mmscf/d range, constrained by water disposal and liquids let down cycles onshore at Bacton
• No unplanned downtime at Blythe year to date indicates improving platform reliability
• Remote platform restart capabilities are now fully established
• The planned Blythe H2 well is intended to increase production rates and limit water production from the reservoir, which would alleviate onshore water handling requirements
• Budgeted cost of £13 million net to IOG, before any tax shelter
• Elgood currently remains shut in, with remaining recoverable volumes to be produced cyclically once pipeline dewatering has reduced back pressure   

2022 Saturn Banks Operational Overview

• Gross gas production from First Gas in March to year end averaged 27.4 mmscf/d (21.8 mmscf/d for 2H 2022) at combined uptime of 58.6% (including planned shutdowns)  
• Average realised gas price over this period was 203.5 p/therm, including short-term price fixes
• 319 p/therm price fix for 30,000 therms/day in place for January 2023
• Gross condensate sales averaged 1067.9 MT/month at $805.3/MT from First Gas to year end
• Total Reportable Incident Rate (TRIR*) of 3.6 per 200,000 manhours 
• Cumulative manhours reached 2 million by end of 2022
• 2022 Scope 1 and 2 emissions intensity estimated at 0.8 kgCO₂e/boe

2022 Financial Overview

• Cash at 31 December 2022 was £32.4 million, of which £5.7 million was restricted  
• Total revenue before sales deductions was £79.6 million
• Cash opex was 13.9 p/therm, in line with guidance of 10-20 p/therm
• Cash capex net to IOG (including long-term lease payments) was £61.2 million, below the £70-85 million guidance range due to slower than planned drilling progress

33rd UK Offshore Licensing Round

• After a rigorous technical and commercial screening process, IOG and its joint venture (JV) partner CalEnergy Resources (UK) Limited (CER) applied for nine Southern North Sea blocks across five licences in the 33rd Round
• All applications are adjacent to existing Saturn Banks JV licences
• All on a 50:50 IOG-CER basis with IOG as operator, as per the JV’s Area of Mutual Interest agreement
• Strong synergies with Saturn Banks portfolio and infrastructure: all licences would fit clearly within IOG’s area plan
• Each licence contains discovered resources that could be added to development hubs  
• Some have field redevelopment opportunities and some have near-field exploration potential
• The UK North Sea Transition Authority is expected to start making the first 33rd Round licence awards in Q2 2023

Rupert Newall, CEO of IOG, commented:
“At the Southwark A2 well we have now taken the production logging data and are preparing to isolate three of the six stimulated zones. Two of the three exposed gas zones will then be re-perforated with a view to improving productivity and the well will then be re-tested. The learnings from A2 are being assimilated into the A1 stimulation programme.

Blythe facilities performance is increasingly stable, with no unplanned downtime year to date and production in the 16-21 mmscf/d range, limited currently by liquids handling at the Perenco Bacton terminal.

The Blythe H2 well is an important part of our plans to maximise production. In a success case, it would enable higher gas rates without associated water production, reducing onshore liquids constraints.

Gross production in 2022, our first year as a producer, averaged 27.4 mmscf/d from First Gas in March, with total IOG revenue of £79.6 million and cash opex of 13.9 p/therm. We ended the year with £32.4 million in cash, of which £5.7 million is restricted.

In the UK 33rd Licensing Round, we have been very active, but disciplined and focused, applying with our partner CalEnergy for nine blocks in five licences across the Saturn Banks catchment area. All potential licences contain gas discoveries that, if awarded, would add value to each of our gas hubs.”

IOG are explaining in some detail the plan for Southwark A2 which will be executed in coming weeks by isolating certain zones.  

With current stable production, help from the Blythe H2 well would increase gas and minimise water production whilst they have reminded the market of the potential upside should they be successful in the 33rd Round where applications for blocks include those with resources close to their gas hubs. 

I’m impressed by the new team who have rolled up their shirt sleeves and are sorting these things out, we can ask for no more and today’s announcement also holds out the hope for exciting local potential in the 33rd Round.

Gulfsands Petroleum

‘Gulfsands Opens New MENA Hub in Abu Dhabi’

On Monday, January 16th, 2023, GULFSANDS celebrated the opening of its Abu Dhabi office, located in the international financial center, Abu Dhabi Global Market  – with an event held at the Rosewood Hotel, Abu Dhabi.

The new subsidiary, Gulfsands Middle East Limited, will be the Group’s Middle Eastern hub. Through the office, Gulfsands plans to step up business development activities in the MENA region and we are very much looking forward to building relationships across government as well as the energy and business sectors in the UAE over the coming months. We will also promote our initiatives to return to operations in Syria – with international support and in a way that benefits all Syrians.

It was a pleasure to host our distinguished guests, including notable personalities from the energy, banking, investment, and media sectors.  Mark Cutis, GMEL Deputy Chairman welcomed the guests and briefly outlined the Company’s humanitarian initiative in Syria. Gulfsands Group CEO, John Bell discussed the Company’s broader strategy and its objectives for establishing a business hub in the UAE. We were honoured to have The Rt. Hon Charles Hendry, former Minister of State for Energy of the United Kingdom as our guest speaker, and appreciated his insights into recent geopolitical developments including their impact on climate diplomacy.

The opening of this new business hub is just one element of Gulfsands’ commitment to the UAE and the region. Gulfsands is also eager to help to create a better future for Syria and its people and will proactively work with all relevant stakeholders towards finding a political solution to the crisis there. The oil and gas industry can – and should – take a leading role in early recovery efforts and Gulfsands looks forward to contributing to this process.

I don’t normally write-up office openings but this is of significant importance, not only to Gulfsands but to the wider industry and how they can not only help the humanitarian initiative in Syria but also to boost the new hub in the UAE both of which deserve success.

Predator Oil & Gas

Predator has announced an update on the drilling of the MOU-2 well in the Guercif Petroleum Agreement onshore Morocco.

The MOU-2 well has been suspended with an option to re-enter after reaching a depth of 1,260 metres Measured Depth.

Wireline logs were acquired from the 95/8” casing point at 677 metres to 1,010 metres Measured Depth. The wireline logging tools were not able to log deeper than this depth due the presence of extremely sticky clays in a geological formation overlying the Moulouya Fan primary objective. Photographs of the logging tools covered in the formation mud have been uploaded to the Company’s website.

Below the logged interval a gross interval of 165 metres was penetrated with up to 100 metres of variable quality sand. A strip log through this interval has been uploaded to www.predatoroilandgas.com. Presence of significant thicknesses of sands demonstrate the potential sand source area feeding the Moulouya Fan below the debris flow.

This geological formation is interpreted to be a slumped basin margin debris-flow which has not been encountered in previous drilling in the area. The clays are particularly under-compacted and sticky due to very rapid deposition within the debris-flow. The interval presented a drilling challenge with very low rates of penetration.

Presence of significant thicknesses of sands in the debris-flow demonstrate the potential sand source area feeding the Moulouya Fan as mapped pre-drill.

Above the depth at which the well was suspended a detached transported block of the Moulouya Fan target may have been penetrated. A gross interval of 28 metres was estimated on the basis of the well site cutting samples and lithological log. 16 metres of potential reservoir was interpreted from drilling breaks. This can only be confirmed by wireline logging.

At 1260 metres Measured Depth a decision to suspend the well was taken as rates of penetration had dropped to below 1 meter/hour.

Forward Plan
The mud programme and its compatibility with the previously not seen sand-rich geological formation represented by the debris-flow will require re-evaluation to achieve a more cost effective rate of penetration.

The debris flow potentially forms a highly effective seal on the underlying Moulouya Fan. The thickness of the Moulouya Fan reservoir interval is expected to increase between MOU-1 and MOU-2 based on the sand content of the debris-flow penetrated in MOU-2 allowed an extrapolation across to MOU-1 to be made.

As a result of this the MOU-1 perforating and testing programme will be more focussed and extensive in the principal zone of interest to determine potential connectivity with the seismically defined area of the Moulouya Fan between MOU-1 and MOU-2 that is interpreted as potentially gas-bearing.

A re-entry and deepening of MOU-2 will be fully evaluated once a solution to optimising the drilling mud programme and mud properties has been completed.

Conclusion
The Moulouya Fan target has not been reached yet in MOU-2 as a consequence of the requirement to re-evaluate the drilling programme through the unexpected geological formation encountered in the well.

Until that re-evaluation is complete and a decision to re-enter MOU-2 has been taken pre-drill objectives remain unchanged as do potential estimates of gas resources.

The MOU-1 testing programme is being progressed and revised to gather as much information as possible on connectivity of potential gas sands over a wide area.

Paul Griffiths, Executive Chairman of Predator Oil & Gas Holdings Plc commented:
“MOU-2 has been an extremely challenging well to drill due to the presence of a particular geological formation not previously encountered.

The prudent and safer option was to suspend the well and leave it in a state to re-enter once a better understanding of the mud programme required to drill this particularly complex interval efficiently and cost-effectively.

Whilst this is not the result we wanted the pre-drill objectives and potential resources remain unchanged.

The Star Valley rig will remain in place over the well head.”

This is way beyond my pay grade and I’m sure that it is right to stop and consider how to re-enter the well with different mud programme etc will work. 

Angus Energy

Angus has announced that the drilling programme at Saltfleetby is likely to be extended by approximately 14 days as a consequence of drilling issues in the Westphalian reservoir and following which the testing phase will commence.

The Company is preparing to mill a new window in the 7″ casing, some 100 metres above the present cased depth of approximately 2400 metres, and to drill directly to target depth in 6″ hole.  Operations to mill the window are expected to commence tomorrow and drilling in open hole will resume before the end of the week.

An infographic of the programme change will be posted on the Company’s website and social media pages over the next two days.

Angus Energy is pleased to announce that Richard Herbert has been appointed a Non-Executive Director of the Company with immediate effect.  It is expected that Richard will rotate into the role of Non-Executive Chairman at the forthcoming Annual General Meeting, with current Chairman Patrick Clanwilliam becoming a Non-Executive Director at that time.

George Lucan, CEO, comments:
“Richard brings broad and deep experience in the oil and gas sector and in particular of managing the challenging onshore drilling environment in the UK.  Angus’ Board is considerably stronger for his presence and we look forward to working with him.”

Richard Herbert comments:
“I am very pleased to be appointed to the Angus Board to support the development and operations of the Company’s strategic asset at the Saltfleetby gas field. After many years in the international oil and gas industry, I am very happy to be returning to work in the onshore UK sector, where I formally worked for BP as the manager of the Wytch Farm oil field in Dorset. Saltfleetby makes an important contribution to securing energy for the UK and is a solid platform on which to build a low-carbon energy company for the future needs of the country.”

Another 14 days won’t make a massive problem at Saltfleetby with a 14 day delay before the testing. 

Capricorn Energy

The Capricorn Board’s priority has been to ensure that the shareholder votes on both the proposed NewMed Combination and the Palliser requisitioned General Meeting on Board composition can occur. To date, it has been necessary to schedule the two votes on the same day to ensure that the option of the NewMed Combination could be maintained.

The Board has listened to shareholder concerns about the timing of the General Meetings, and has therefore been considering the Company’s obligations under the Business Combination Agreement entered into with NewMed on 29 September 2022 (the “Business Combination Agreement”), and discussing with the FCA the requirements of the combined prospectus and circular published by the Company on 13 January 2023 (the “Prospectus/Circular”) and now intends for the NewMed GM to be adjourned from 1 February until 22 February 2023.

The Requisitioned GM will go ahead on 1 February 2023, with an adjournment of the NewMed GM allowing a reconstituted Board to assess the proposed NewMed Combination alongside other strategic options prior to determining the recommended route forward. NewMed is aware of the intended adjournment of the NewMed GM and has advised the Company that it reserves its rights under the Business Combination Agreement.

To best enable the process of Board reconstitution, the following changes to the Board have been collectively agreed:

• Nicoletta Giadrossi has accelerated her decision to step down as Chair following the proposed NewMed Combination vote, and will step down from the Board with immediate effect;
• Simon Thomson will step down as a Board director with immediate effect;
• Peter Kallos, Alison Wood and Luis Araujo will also step down from the Board with immediate effect;
• Keith Lough remains on the Board to ensure ongoing oversight of reporting obligations and other corporate governance requirements with the intention of stepping down from the Board in advance of the Requisitioned GM; and
• similarly, James Smith remains on the Board as Chief Financial Officer, with the intention of stepping down from his role as Board director in advance of the Requisitioned GM.

The Company has been in discussions, via Palliser, with the Requisitioned GM nominee directors (the “Nominee Directors”) to seek to appoint them to the Board immediately, but understands that the Nominee Directors’ preference is to wait until the Requisitioned GM on 1 February. The continuing directors, including Cathy Krajicek and Erik B. Daugbjerg, will engage with the Nominee Directors to ensure an orderly transition and appropriate continuity of governance. A further announcement on Board reconstitution will be made in due course.

What a mess! When I wrote all those months ago when Cairn capitulated to Tullow, how bad it looked, and that they had ceded the top jobs, all their cash and even the beloved Edinburgh office little did I know that it could actually get even worse. 

Now most of what remains of the board has only stayed behind to pass the skeleton on to whoever next pitches up at the Lothian Road and for the cost of a night at the Sheridan could come away with the booty. 

Palliser and NewMed meetings will likely come and go next month and after that who knows what might become of Bill Gammell’s baby, I don’t suppose that Vedanta is still around in some shape or form….?

Getech

Getech yesterday announced an update on trading for the year ended 31 December 2022 and current outlook.

Financial Highlights – Continued Growth

• Double-digit revenue growth, ahead of market expectations: £5.0 million (FY2021: £4.3 million) with a 66%/23% split between transitional petroleum and critical minerals
• Record orderbook: £4.6 million, a 39% increase (31 December 2021: £3.3 million, +25% on 2020)
• Strong cash position: £4.3 million at 31 December 2022, with cash held flat across H2 2022 by sales momentum and careful capital management (31 December 2021: £5.9 million)

Strategic Progress – Aligned to Global Energy Transition

• War in Ukraine led to renewed focus on energy security and underlined the role of oil and gas as transitional sources of primary energy. In 2022, Getech continued to benefit from high petroleum customer retention rates and, by aligning its offering with carbon storage solutions, Getech is futureproofing its role in a sector that is expected to remain a significant near-term engine of revenue.
• In the last two years, Getech has built new low carbon solutions for critical minerals, geothermal, green hydrogen and carbon storage by repurposing data and software that it developed for the petroleum industry.
• Value proven – In 2022, customers have purchased Getech’s solutions to locate copper, gold, cobalt, and helium, to manage carbon storage licensing rounds and to explore for geothermal energy. Getech is now expanding its offering to include lithium and natural hydrogen.
• Significant potential to scale-up revenue from other sectors looking to decarbonise – In 2022 Getech secured its first fast moving consumer goods customer, delivering an integrated decarbonisation solution for their global portfolio of assets that helps them achieve their ESG objectives.
• When locating energy and minerals, Getech may selectively obtain a carried/low-cost interest at the early stages of an asset’s life cycle, in lieu of revenue, thereby building an asset base to create long term shareholder value. Getech will retain multiple options to monetise such positions with the aim to maximise value and minimise capital risk.
• Getech has formed a strategic partnership with Eavor, a global geothermal technology company, to jointly locate and appraise closed-loop geothermal projects in Latin America.
• At Shoreham Port, Getech increased phase 1 hydrogen design capacity from 800 kg/day to 2.5 tonne/day due to bigger local demand and extended its commercial exclusivity to 2027.
• In Inverness, progress was slowed by a reshuffle in the executive team of council officers and a focus on securing the Cromarty Firth Greenport. Discussions with the Highland Council about the Highland Hydrogen Network have now regained momentum.
• To accelerate value creation and reduce Getech’s direct costs in establishing green hydrogen transportation hubs, the Company is advancing discussions with strategic investment partners and progressing significant grant funding opportunities.

Strong Outlook

• Getech starts 2023 with a strong balance sheet, sales pipeline growth, plus good customer and partner momentum. Getech’s Board has no current plans to raise capital from shareholders.
• Work to sell Kitson House is progressing, and the property is currently under offer. However, completion of this sale has been impacted and delayed by the ongoing volatility in the commercial lending market.
• The macro environment outlook remains strong for companies such as Getech that are focussed on the energy transition. Forecasts indicate that a $1 trillion per annum increase in energy investment is required to resolve the dual challenge of energy affordability and security, across both clean energy and hydrocarbons.

Dr Jonathan Copus, Getech CEO commented: 
“Our consistent year-on-year growth reflects the strength of our integrated solutions and the urgency of energy security and transition. Leveraging our unique digital twin of the Earth with 400 million years of data we are well-positioned to analyse the subsurface for the benefit of accelerating net zero achievement. We can locate sweet spots for geothermal energy, critical mineral deposits, hydrocarbon accumulations, zones for carbon storage, and the best places for green hydrogen mobility sites.”

“While we are making good progress with our development projects at Shoreham and Inverness we also continue to generate revenue from our extensive data, cross-sector expertise and advanced analytics through licensing and solution sales.”

“Looking ahead, we are confident that our solutions will gain even more momentum as every company is now facing the challenge to decarbonize their activities. We have a strong pipeline for this year and beyond, which will fuel the company’s continued growth – unlocking value for all stakeholders.”

I’ve followed Getech for longer than most and it’s all beginning to look rather tasty, almost as envisaged all those years ago. This set up a more than decent set of figures where the move towards geothermal, hydrogen and carbon storage appears to be paying off. 

The order book is up from £3.3m to £4.6m which bodes well and as Dr Copus says the pipeline will fuel the company’s growth. 

Serica Energy

Serica yesterday announced that it has received a renewed License and secondary sanctions assurance from the US Office of Foreign Assets Control (“OFAC”) relating to the North Sea Rhum field, in which the Company has a 50% interest. The License and assurance will allow certain U.S. and U.S.-owned or controlled entities and also non-U.S. entities to continue providing goods, services and support to Rhum beyond 31 January 2023, when the current License was due to expire. This will enable operations and production from the Rhum field delivering gas supplies to UK consumers to continue unaffected. The new License is for a period of two years with an expiry date of 31 January 2025. The License may be renewed on application by Serica assuming the conditions continue to be met.

Mitch Flegg, Chief Executive of Serica Energy, commented:
“Once again we have secured a prompt renewal of the OFAC License for a period of a further two years. We are grateful to the UK government and regulatory authorities who have supported us in this process.

The renewal of this License satisfies one of the Completion Conditions required for the acquisition by Serica of Tailwind Energy Investments Ltd.”

What is says on the tin…

Kosmos

Kosmos Energy announces that the floating production, storage and offloading vessel (“FPSO”) for the Greater Tortue Ahmeyim (“GTA”) liquefied natural gas project has departed the COSCO shipyard in China to commence its voyage via Singapore to the project site on the maritime border of Mauritania and Senegal. The voyage is approximately 12,000 nautical miles and the vessel is expected to arrive in the second quarter.

Chairman and Chief Executive Officer Andrew G. Inglis commented:
“The sailaway of the GTA FPSO from the shipyard in China is a key milestone for the project. At the end of 2022, the project was around 90% complete and we look forward to an active 2023 where we expect to achieve a number of important milestones for the project and the company.”

A key milestone passed and the sailaway is a joy to see for those of us who have watched the progress from afar. I’m a bit out of touch with Kosmos but I’ve always liked its vim and vigour, not long before the dog catches the hare, so to speak…

Canadian Overseas Petroleum Limited

COPL yesterday announced the first oil production from the Frontier 1 sands at its operated 100% WI Cole Creek Unit.

Highlights

• First successful Frontier 1 oil completion at Cole Creek since Frontier 1 oil was first identified by the original Unit operator in 1943;
• 11-27-35n-77w well is currently pumping 125-135 bbl./d of fluid through 65′ of unstimulated perforations, with gasified light oil cuts of up to 86% observed late last week;
• Well clean-up is continuing with near well-bore damage caused by invasion of significant volumes of light fresh water drilling mud during drilling 10.5 years ago;
• COPL expects conversion of Frontier 1 Prospective Resources to Contingent Resources and ultimately Reserves as additional producing wells come online;
• The Company has defined an “Oil Down To” elevation for the Frontier 1 at Cole Creek with an area of approximately 8,000 acres;
• The Frontier 1 recompletion program at Cole Creek will continue with 4-27-35n-77w.

In the last week of December, the Company initiated recompletion operations on the well 11-27-35n-77w to evaluate the light oil potential of the Frontier 1 reservoir sands. Light oil was first identified in the Frontier 1 at Cole Creek in 1943 by the then operator General Petroleum Corporation, the operating affiliate of Standard Oil of New York (Mobil Oil). The 11-27 Frontier 1 completion was the second completion attempt in the Frontier 1 in Cole Creeks history. The first attempt was in 1966 by Mobil and was unsuccessful. All well records available to the Company indicate moderate to severe fluid losses into the Frontier 1 during drilling and cementing operations at Cole Creek, and the areas to the east thus making Frontier 1 completions challenging. This was the case the 11-27 well as well as our 14-30-35n-76w exploration well of 2021.

The lowest of three Frontier 1 sands was perforated with sixty-five feet (65′) of perforations with no subsequent stimulation. Initial fluid recoveries were: black heavy degraded oil, black emulsion, minor brown un-gasified light oil and water. In excess of 800 Bbl. of light fresh water drilling mud was lost into the formation during drilling 10.5 years ago, as well as cement during cementing operations. The well was then put on pump for clean up as it is the most cost-effective method to recover the invaded fluids and the resultant fresh water degraded crude oil from the near well bore area.

Fluid entry from the reservoir has remained constant through pumping at rates between 125-135 Bbls/d. Gasified light oil volumes increased over the last week with increasing oil cuts up to 86% at week’s end, with the well slugging heavy black degraded oil, emulsion and drilling mud periodically at higher water cuts (up to 85%). The proportions of heavy black degraded oil, emulsion and drilling mud are decreasing as the well continues to clean up through pumping operations. COPL has opted to continue with the current process of well clean up rather than a hydrocarbon-based stimulation to remove the degraded oil and emulsion from the near well-bore area. A stimulation of this type would remove the damage, though at a significant cost, monetary and time.

Oil production from the Frontier 1 from the 11-27 well at Cole Creek will have an impact on the Company’s petroleum resources through reclassification of Prospective Resources to Contingent Resources, and ultimately its Reserves as additional producing wells come online.

An “Oil Down To” elevation at the base of the Frontier 1 perforations has been determined. This elevation is approximately 760′ below the crestal elevation of the Cole Creek Anticline. The area within the “Oil Down To” elevation is approximately 8,000 acres with reservoir sand thickness ranging from 50-115′, thinning in the northern area. Approximately 50′ of Frontier 1 sands remain unperforated in the 11-27 well. These sands will be completed when the perforated sands in 11-27 are hydraulically fractured as part of a stimulation campaign on the recompleted wells later this year.

COPL is continuing with its Cole Creek Frontier 1 recompletion program. The second well in the program is 4-27-35n-77w. It is located approximately 0.5 miles northwest of 11-27 with the reservoir sands 230′ higher in elevation. The lower Frontier 1 sand will be perforated with fifty-six feet (56′) of perforations. In common with 11-27, no stimulation of the perforations is planned. Reservoir quality from wire-line logs from 4-27 well appears to be better than the reservoir perforated at 11-27. Operations will commence when services required become available.

Arthur Millholland, President and CEO Commented:
“The results from the Frontier 1 11-27 recompletion is a game changer for our Company as the defined oil-bearing reservoir currently covers a large area at Cole Creek with evidence it extends further down dip on the east flank of the anticline. These results have also confirmed our internal evaluation of the Frontier 1 after the drilling and evaluation of our 14-30 exploration well last year. All of the wells with wireline logs from the 1970’s to present have similar petrophysical characteristics within our mapped trends. At Cole Creek we only have 6-7 well bores with sufficient integrity for recompletion and hydraulic fracturing. One of these wells, 12-23-35n-77w had oil flow observed at surface due to reduced mud returns during drilling of the Frontier 1 at an elevation below the “Oil Down To”. We will get to it in time.”

 I have enjoyed picking up COPL and my timing has been quite good, surely by chance I assure you. The good news here will be proven by increases in production, revenues and of course reserves…

KeyFacts Energy Industry Directory: Malcy's Blog