Northern Petroleum is an oil and gas exploration and production company quoted on the AIM market. Their key assets are in Canada, an onshore oil production play with significant growth potential, and in Italy, with both onshore and offshore permits and applications containing exploration prospects and discovered oil fields.
The group has various licenses. In Canada they have 94 leases in the North West Alberta onshore asset. In Italy they have a 20% interest in the Cascina Alberto onshore permit with Shell Italia being the 80% interest holder and operator. Offshore they have two permits in the Southern Adriatic and five applications, all 100% owned. Offshore in the Sicily Channel they have two 100% owned permits, a 100% owned application and two 50% owned applications, one operated by Petroceltic. They also have a 100% owned application offshore in the Ionian Sea. In French Guyana they own a 1.4% interest in the offshore Guyane EEL license with Shell being the operator. Finally, in Australia they own a 100% interest in the onshore PEL629 license.
In Canada the Keg River carbonate reef redevelopment project in NW Alberta is targeting production from more than 80M barrels of light oil remaining in place in the 30,000 acres owned by the group. The reefs on the group’s acreage produced from the 1960s through to the early 2000s, with significantly lower recovery factors than surrounding areas. The opportunity exists to put the fields back on production. In Australia the large acreage in the Otway basin is primarily targeting an unconventional oil and gas play, currently available for a farm out. In French Guyana the acreage contains the Zaedyus oil discovery and additional prospects within a large deepwater exploration license. Monetisation of the interest is currently being considered.
In Italy, the group owns five permits onshore and offshore and a large area of applications in the Adriatic, an area of recent interest by the industry following the licencing rounds in Croatia and Montenegro. The Adriatic permits contain the Giove undeveloped oil discovery with 26M barrels of 2C contingent resource, and the potentially significant Cygnus exploration prospect. Onshore the group has recently farmed out its Cascina Alberto permit to Shell Italia who will operate the permit through the exploration work programme. Building and maturing a broad collection of exploration and appraisal assets in Italy will provide opportunities to create value for the group.
Northern Petroleum has now released its final results for the year ended 2014.
Although revenues from the UK fell, the group made their maiden revenues from Canada, and after production costs also increased, gross profit improved by $258K year on year. Pre-license costs also fell, along with operating lease rentals, share scheme costs and other admin expenses. We also see a $2.3M profit on disposal of assets relating to the sale of the UK assets and nearly $1M less in new business expenses when compared to last year. Unfortunately all this was dwarfed by the impairments with a $9.4M increase in oil and gas impairments, an $18M increase in exploration asset impairments and a $744K impairment of the IT system to give an operating loss some $21.9M bigger than in 2013 at $57.3M. After a smaller foreign exchange loss, a much lower tax credit and the lack of a $2.8M loss from discontinued operations, the loss for the year stood at $59M. Some $16M of these losses was attributable to non-controlling interests (namely HALO, who own the 44.1% of the French Guyana assets through their investment in Northpet), however, so that the loss attributed to the owners came in at $43M, an increase of $3.6M year on year.
When compared to the end point of last year, total assets fell by $62.1M driven by a $36.5M reduction in the value of the French Guyana exploration assets, a $23.7M fall in cash, a £3.5M fall in the value of Italian exploration assets and a $1.6M decline in the value of IT systems partially offset by a $3.5M growth in the value of the Italian oil and gas assets. Total liabilities increased during the year as a $749K increase in accruals and deferred income, and a $1.1M growth in trade payables were partially offset by a $406K decline in deferred tax liabilities and a $328K fall in the Italian Government loan. The end result is a net tangible asset level of $7.3M, a collapse of $22.5M year on year.
Before movements in working capital, cash losses widened by $5.3M to $5.1M. A fall in receivables and an increase in payables meant that after interest and tax, the group lost $2.7M from operations, a $491K improvement year on year due to the much smaller tax payment. The group spent $11M on producing assets and property, plant and equipment, and some $11M on exploration before an inflow of $2.5M from the sale of a subsidiary meant that the cash outflow before financing stood at $22.2M. After government loans broadly cancelled each other out, the cash outflow for the year stood at $22M to give a cash level of $12.1M at the year-end which is clearly not a sustainable situation.
At the year-end the group has cash of $12.1M and they expect to make future revenue from existing oil and gas fields but further development or drilling in Canada and appraisal activities on the group’s assets in Italy will require external capital, which may come from the farm out of existing assets, the sale of non-core assets, debt or equity. The board believe that they have sufficient resources to continue in operation at least until the end of 2016.
In Canada the group started proof of concept work in the Virgo area of NW Alberta, aiming to redevelop Keg River carbonate reefs with low recovery factors, using workovers of existing wells and the drilling of new wells. The positive results from the first three wells resulted in a redevelopment programme being initiated with the expectation that the year-end exit production rate would be over 500 bopd. The initial three wells were placed on production using rental equipment with the fluids trucked to the local processing facility, pending tie-in to the existing infrastructure which gave a stabilised production of more than 200 bopd at the half year point.
The results of the three wells drilled in the second half of the year were mixed with one well testing at more than 1,000 bopd, one at 20 bopd and the third proving swept with water. The high rate well was tied in to the existing local infrastructure and, combined with the initial three wells, allowed production to peak at more than 500 bopd just before the end of the year. The declining oil price postponed further capital investment to tie in the three original wells due to a much longer investment payback horizon, however.
The key uncertainty with the three wells drilled in the second half of the year proved to be the ability to correctly identify the top of the reservoir from interpretation of the seismic prior to the wells being drilled. This, along with the impact of water injection into other reefs on reservoir sweep, led to the poor results of two of the wells. The top reservoir came in where expected proving the revised seismic model. One of the wells produced oil at a rate of 90 bopd from a top reservoir section but with significant amounts of water making the well uneconomic in the current oil price environment. Analysis is underway to determine whether the water was being produced from a separate zone not completely isolated by the cemented liner, or the dynamic nature of the reef system is more complex than previously understood.
At the end of the year, a reserves report for the Virgo assets was commissioned, reviewing the first three wells and the high rate well from the second round of drilling. Using current oil prices, they assigned proved reserves of 144,000 barrels of oil and additional probable reserves of 149,000 barrels of oil. These wells generate a net present value at 10% discount rate of approximately C$4M.
In Canada two drilling campaigns, each of three wells, were undertaken during the year. The first three wells comprised a re-entry into an existing well (100/14-22); a new well into a previously undrilled reef (100/16-19); and a new well into a previously produced reef (102/13-13). The results of the 100/14-22 well prove the concept of oil re-equilibration since when the well was brought back into production, the well had a peak daily rate of 100 bopd with an initial water cut of 40%, an improvement on both measures from when the well was shut in previously in 1991.
The results from the 102/13-33 well support the concept that larger reefs developed with only a single well contain remaining un-swept oil zones that can be targeted by drilling new wells. The well had a peak daily rate of 260 bopd with an initial water cut of 36%. The result of the 100/16-19 well, an exploration well, highlighted that structures may exist which have not been identified in the past and provided additional information to assist with the subsurface identification of future well locations. The well had a peak rate of 140 bopd of dry oil.
The second campaign of three wells drilled during the summer and autumn all targeted unswept zones at the edges of previously produced reefs. The result from the 102/15-23 was exceptional with the well encountering 14 metres of net oil pay and flowing on test at a facilities constrained rate of 1,300 bopd of dry oil. The 100/14-23 well encountered four metres of net oil pay and produced at a rate of 20 bopd during swabbing, while the 100/1-27 well encountered an unexpected overpressured and water swept reservoir. Both wells were subsequently suspended without being tested and have been impaired on the accounts while awaiting further evaluation. The wells prompted a focused subsurface review aimed at delivering similar higher performance results as seen by the 102/15-23 well. The review refined the subsurface understanding, primarily through revised seismic interpretation, well location optimisation with respect to nearby production wells and the understanding of reservoir sweep behaviour.
Other activities in Q4 2014 concentrated on the installation of the surface facilities and the tie in of the 102/15-23 well, along with well planning for the next drilling phase. The facilities work was completed before Christmas and following the tie-in for the 102/15-23 well, production was progressively increased up to the new year enabling the group to achieve a total field production rate from all four producing wells of more than 500 bopd.
In early 2015, the planned two well drilling programme was reduced to a single well in a response to the rapidly falling oil price. The 102/11-30 well was located down flank of the reef structure in order to investigate the possibility of unswept oil on the reef edge. The well reached the top of the Keg River formation in line with prognosis and encountered the expected reservoir section. When tested the well flowed at 90 bopd with a water cut of 85%. As a result the well was suspended pending a subsurface and facilities review to determine the source of the water and establish a cost effective method of handling the water. The results from these wells will be incorporated into a revised sub-surface model which is expected to be completed during Q3 2015 and no further wells will be drilled until it has been completed.
In the current reduced oil price environment, a reduction in development and production costs will be crucial in delivering an economic project in Alberta, hence the impairment of the Canadian project. Should the low prices continue, it is expected that there will be a reduction of operating costs due to downward price pressure on the supply chain coupled with a reduction in rig and associated service industry rates by H2 2015. In the meantime the group is investigating alternative operating strategies for the existing wells in order to reduce variable operating costs. In all, the group produced 30,685 bbls from the country and generated revenue of $2.2M. Stable production at the year-end was 275 bopd with a peak of over 500 towards the end of December.
In Italy the focus was to continue to liaise with industry and government authorities for approval of the environmental impact assessment to allow the acquisition of 3D seismic data to be made in the southern Adriatic permits, F.R39.NP and F.R40.NP that contain the Giove oil discovery and the Cygnus exploration project. Elsewhere the award of the onshore Cascina Alberto permit and offshore C.R149.NP permit in the Sicily Channel demonstrated that the regulatory authorities are providing the support needed to move forward within Italy. The Giove undeveloped oil discovery has been assessed to contain 2C contingent resources of 26M barrels of oil. The planned 3D seismic survey should help in locating an appraisal well on the field required to establish a viable development plan. The results from the most recent sub-surface analysis indicate that there is potential for improved reservoir properties and a higher recovery factor.
The Cygnus prospect remains a high priority and is the primary focus of the 3D seismic survey. It is interpreted as having a proximal reservoir sequence to the equivalent distal reservoir sequence that forms the reservoir in the adjacent Aquila oil field. The assessment of the prospective resources for the Cygnus prospect assigned 978M barrels in the high case estimate, using a common oil water contact with the Aquila field, of which 790M barrels of prospective resources are net to the group on the F.R39NP permit. In the mean case, using a shallower contact and assuming there is separation of the mapped prospect from the Aquila oilfield, a prospective resource estimate of 446M barrels have been assigned, of which 401M barrels lie within the permit. There is an estimated chance of success of 12% for the Cygnus prospect.
The group is seeking a farm in partner to progress the work programme, which will include the acquisition of 3D seismic data across both the Giove oil field and Cygnus prospect that will further enhance the potential to progress with a Giove oil field development and the drilling of an exploration well on Cygnus.
Onshore in Italy, the Cascina Alberta was awarded in July 2014. The area was held in the late 90s by Eni which focussed on a prospect called Gattinara that previously interpreted as holding a prospective resource of 300M barrels of oil. The trap is similar to structures such as the Villafortuna-Trecate field, which is located 25Km to the South East. In early 2015 the group announced a farm out deal with Shell Italia whereby in return for an 80% interest and transferred operatorship to Shell Italia, Shell will pay $850K in cash on completion and will carry the group for the costs of the exploration campaign which will include a carry on the authorisation of any new seismic until the seismic costs reach $4M and a carry on any exploration well until the well costs reach $50M. Shell have a pre-emptive right over the company’s remaining interest in the Cascina Alberto permit in the event of any change in control at the asset or corporate level.
In the Sicily channel, permit C.R149.NP was awarded in July and is adjacent and to the East of C.R146.NP and contains an extension of the Vesta oil prospect. The prospect is interpreted as having the same age reservoir sequence as the on trend Vega oil field. Permit C.R146.NP is currently held in suspension while an environmental impact assessment to drill an exploration well is processed through the Ministry of Environment. Applications closer to the Sicilian coast contain leads similar to the on trend Palma oil discovery and are also pending environmental impact assessment approval before permit award. Following the year the group announced a joint technical study with Schlumberger and GEPlan. The study will cover a large area of the Streppanosa Basin which includes C.R146.NP and C.R149.NP, with the objective of promoting and high grading the area for exploration.
In the Ionian Sea, within application d59F.R-.NP there are three deep water gas discoveries Fiorenza, Fedra and Florida drilled in 1982, 1987 and 1999 respectively by Agip. The gas discoveries are adjacent to the producing Luna, Hera Lacinia and Linda gas fields operated by Eni. Additional exploration prospects are contained within the application and these together with the existing gas discoveries will be evaluated on the pre-existing Eni 3D seismic survey once the permit has been awarded.
In Australia two deep wells were drilled by Beach Energy on adjacent acreage to provide further support for the play concept. The license is suspended for a year to allow further technical work and evaluation prior to progressing with a seismic programme. The group is seeking a farm in partner for the license. The UK license portfolio was sold to UK Oil and Gas Investments in October 2014 for a consideration of £1.5M.
The French Guyana drilling campaign was completed in 2013 and Shell, the operator, is currently incorporating the results into its geological model to better understand the considerable remaining prospectivity and determine the future license work programme. While subsurface analysis is still ongoing any future exploration or appraisal wells are contingent on the satisfactory outcome of this analysis and would most likely require an extension of the license which expires in mid-2016. With this level of uncertainly concerning future exploration, it has been deemed appropriate to impair the full value of this asset. The assets in French Guyana are held through Northpet investments, some 55.9% of which is owned by the group. The group are looking into ways to monetise the investment in the license.
During the year the group had impairment losses relating to accounting and procurement IT systems implemented in early 2012. Following the disposals of three UK operating subsidiaries during the year and of the Netherlands subsidiary last year, the carrying value of the IT systems have been impaired by 40% to reflect the redundancy of system modules and functionality previously used to meet joint venture agreement requirements. Other impairments include the impairment of the carrying value of leasehold improvements following the disposal of one of the office floor leases and the planned relocation of the head office in April 2015.
Following the drilling of the development wells in Canada and the halving of the oil price in late 2014, and after a review of the performance of all the producing wells, impairment losses of $15.3M were recorded against the Canadian developed assets. In order to reach these judgements, the directors have used average oil prices of $50 in 2015, rising to $85 by 2017.
Last year the group impaired some $1.4M owing to the group from Avobone from the drilling of the Savio 1x well. In March they agreed a settlement involving cash payment and transfer of a VAT debtor of $1.1M which left $600K outstanding. The group is pursuing the recovery of the VAT debtor but the timing of any cash receipts is uncertain and could take a number of years. During the year the associate company, Oil and Gas Investments, was dissolved. $49K trade debtors due from the associate were written off in the year.
In February the group announced that Well 102/11-30, targeting a reef previously undrilled by the group was drilled and tested as planned. A significant reef section was encountered, as forecast from seismic interpretation. Two separate zones were isolated and tested. A lower zone, which was water wet and an upper zone which produced oil but with too high a water content to be economic in the current oil price environment. The well was suspended for further evaluation.
During the year Graham Heard departed from the board after spending many years with the company and there is no plan to replace him. In addition Stewart Gibson retired from the board in early 2015 as a result of the need for the group to manage costs throughout all areas of the organisation.
At current commodity prices, the existing financial resources provide limited scope to materially advance the core assets of the business and may be exhausted by the end of 2016 without the realisation of cash resources through farm out or other monetisation projects. Production led growth is still the key strategy for the group but the fall in the oil price meant that only one Canadian production well was tied into the existing local third party infrastructure and with the high cost involved in trucking significant amounts of water, the decision was taken to shut in the other wells at the start of 2015.
At the year end, the group had cash of $12.1M and there was $1.3M of debt outstanding relating to the Italian Government loan which is repayable over five years. The group does not make a profit so we can’t value it on a PE ration basis.
Overall then, this has clearly been a difficult year for the group, as it has been for many small oil companied following the hefty decline in the price of oil. There were increasing losses due to more impairments but underlying losses were a bit lower than last year. Net assets collapsed, however, as there was a large outflow of cash. Operating cash losses fell year on year but this was entirely due to hardly any tax being paid and underling cash losses actually increased during the period. At the year-end the group had cash levels of $12.1M but since then another well has been drilled and the cash is only likely to last until the end of 2016 without any farm in cash being received.
As far as the assets themselves are concerned, the only producing asset, located in Canada seems as though it is unlikely to be able to contribute much to cash flow in this low cost environment and my understanding is that there is only one well currently producing there. The Australian and French Guyanan assets don’t look as though they will come to much but the Italian acreage does look rather interesting. Clearly they will not be able to go alone with any of the assets but the farm out to Shell looks like a good way forward for progressing these in this environment. Overall, I think this company might have potential in Italy but investing in the current environment is pretty much impossible in my view.
On the 8th May the group announced that the farm out of the Italian onshore permit, Cascina Alberto, to Shell Italia, had been completed following the Italian authority approval of the transfer of 80% of the permit interest in return for $850K a carry of the exploration costs as previously announced. The work programme has started with the re-processing of existing seismic data to determine whether there is a requirement for further seismic acquisition to help delineate a proposed target for an exploration well.
On the 11 May the group released details of their new incentive schemed for the directors as obviously their generous salaries are not enough to motivate them to work hard. The key principle of the new policy is apparently to link any reward only to the performance of the company’s share price over the medium term. Under the VCP, participants have been awarded performance 1,000,000 “performance units”. The units will convert into nil-cost options at three dates during a five year period if a number of criteria are achieved. I do hate nil-cost options! The threshold price is the higher of a 20% per annum compound growth rate from the grant price (15p per share) and the measurement price used at a previous measurement date.
The measurement dates are in May 2018, 2019 and 2020. Any nil-cost options earned at each measurement date will not be exercisable until the end of the five year measurement period and all participants are required to build up a shareholding equal to their base salary by the final measurement date. This actually seems fairly sensible – the shares have to increase by 20% and the directors have to remain in place to obtain the options so the scheme looks OK to me.
The NPIP is another scheme that has been established to create a rolling, three year share incentive for all staff and to govern share based awards made as part of any annual bonus to directors and senior management. In May the directors were granted awards in the form of nil-cost options which are the deferred annual bonus shares in respect of 2013. These awards have not been granted until now due to the company being in successive closed periods since the 2013 bonus award was determined (this seems a little odd to me). The awards vest in January 2017 and include 209,644 for CEO Keith Bush and 167,715 for CFO Nick Moran. I have to say this sits a little less well to me, what exactly are these directors being awarded for?
On the 19th May the group released a production update for the Canadian assets. A production package for the 100/16-19 well was purchased and following implementation of some design changes is now ready to be installed at the well pad. The package includes an 800 barrel storage tank, separator and flare stack. The pump and heater have also been configures to be powered by associated gas produced from the well which brings cost savings. The larger storage tank will provide better onsite oil and water separating capability and a reduction in regular trucking movements, which will benefit production uptime during the wet periods. Starting in June, the well is expected to produce at 75 to 100 bopd subject to well reservoir performance and associated water production.
The pump on the 102/15-23 has now been installed and the local operator, who owns and manages the pipeline and processing infrastructure that the well is tied into, has undertaken a programme of maintenance which has affected the well. Work required to ensure the integrity of the pipeline that the well tied into will be conducted early in Q3, after which production will restart. An initial production rate of about 150 bopd is planned and reservoir performance and water cut will determine future production rates and decline.
The remaining wells have a total production capacity of 250 bopd at water cuts greater than 50%. Establishing disposal of the produced water as economically as possible is key to the restart of production from these wells. Other operators in the area have demonstrated that wells can produce economically at water cuts greater than 95% and the company is now reviewing operations for each well to ensure the recovery and value from the wells is maximised. At $55 WIT, operating net back after royalty is forecast to be approximately $30 per barrel and at current oil prices, net cashflow from both wells is expected to cover most of the total general and admin costs of the company.
I have to say, it is good to see 100/16-19 being re-opened and the fact that just these two wells should be able to support the company is very positive. Having said that, it appears that the company currently has no wells in production so the first half results are likely to look a little poor.
In June, the group announced that its environmental impact assessment (EIA) for the acquisition of 3D seismic data across the Giove undeveloped oil discovery has been approved by the Italian regulatory authorities. In addition, EIAs for two of the company’s exploration permit applications have been approved. This will allow the company to continue its exploration and appraisal campaign in the Southern Adriatic. There are three further EIA applications in the area which are expected to be approved shortly.
On the 11th June the group announced an update of the production activities in Canada. At well 100/16-19, the new package was installed and following a period of commissioning the well started production on the 7th June. It has flowed without incident on pump at a rate in excess of 100 bopd. The well is expected to produce at between 75 and 100 bopd, dependent on future reservoir performance and associated water production. At the 102/15-23 well, the maintenance work being undertaken by the local operator is expected to take four to six weeks, after which production will restart with a planned initial production rate of 150 bopd.
On the 16th June the group announced that the Italian authorities had approved the remaining three EIA in the Southern Adriatic. Now all EIAs have been approved, the company can now work with the Italian authorities to finalise the award of the permits. Once received, a full 2D seismic programme will be designed to evaluate the potential of the 4,500 sq km of contiguous permits and develop further opportunities similar to the Giove discovery and Cygnus exploration prospect.
This is not a chart that inspires me to invest at the moment.