Northern Petroleum has now released its final results for the year ended 2015.
Revenues crashed by $2.4M to just $332K this year and with a $1.8M fall in production costs, the gross loss worsened by $587K when compared to last year. Depletion and amortisation therefore fell by $696K, depreciation of non-oil assets declined by $389K and other admin costs fell by $2M. We also see the lack of a $2.3M profit on asset disposals that occurred last year offset by $786K of other income representing the cash consideration of the Italian farm out, a $33.4M fall in exploration asset impairments and a $12.7M decline in oil and gas asset impairments to give an operating loss which improved by $47.3M when compared to 2014. Finance costs reduced by $1.1M and the income tax credit increased by $437K to give a loss for the year of $10.1M, a decline of $32.8M year on year.
When compared to the end point of last year, total assets declined by $17.2M driven by a $9.7M decrease in cash, a $4.6M fall in Italian exploration assets due to impairments and exchange differences, a $1.1M decrease in other exploration assets due to exchange movements, a $1.1M fall in the value of IT systems and a $915K decline in receivables. Total liabilities also declined due to a $4.6M fall in payables and an $861K decline in deferred tax liabilities. The end result is a net tangible asset level of $2.2M, a decline of $5.1M year on year.
Before movements in working capital, cash losses decreased by $2.2M to $2.9M. There was a large fall in payables which meant that, after a modest tax receipt, the net cash outflow from operations was $6.4M, an increase of $3.7M year on year. The group also spent $4M on property, plant and equipment, mainly relating to the drilling of the 102/11-30 well in Alberta, along with $1.1M on exploration so that before financing there was a cash outflow of $11.5M. The group received $2.4M from the issue of shares and repaid a $382K government loan to give a cash outflow for the year of $9.5M and a cash level at the year-end of just $2.4M.
In Canada, early in 2015 the 102/11-30 well was drilled targeting upswept oil on a reef edge location. The well encountered the reservoir as expected and when tested the well flowed at 90 bopd but with a water cut of 85% so the well was suspended. With the production in Virgo not economic at the prevailing oil price and remaining high costs at the start of the year, combined with the use of rental equipment, all wells were shut in during January 2015 while lower operating cost options were evaluated. Subsequently the group purchased and installed a new production package on the 100/16-19 well and brought this well back into production in June at a rate of 75 bopd.
The 102/15/23 well, which was tied in during 2014, was shut in by the third party operator in Q1 2015 due to concerns about the integrity of the gathering pipeline the well was tied into. The operator of the gathering pipeline subsequently decided that it was uneconomic for them to reinstate the line, therefore the group acquired operatorship of the pipeline and reinstated production from the well in early 2016 at a rate in excess of 100 bopd.
Early in 2016 the group completed the acquisition of the Rainbow assets, about 15 miles from their existing Virgo development. As well as adding 1.1M barrels of oil equivalent of 2P reserves, the acquisition also included two processing facilities providing significant cost savings for production from the group’s trucked Virgo area wells and potential third party processing fees. At the time of the acquisition the Rainbow facilities were producing about 200 bopd and the group identified an initial low cost work programme involving facility repairs and well workovers that aim to increase average group production for 2016 to 400 bopd. Activities in early 2016 have focused on the Rainbow area and the restart of the 102/15/23 Virgo well, resulting in average production in March in excess of 400 bopd.
In Italy, the group has obtained approval of six EIAs in the southern Adriatic; one for the proposed 3D seismic programme across the Giove oil discovery and Cygnus exploration prospect and five others for exploration permit application areas. Approval of these EIAs has allowed them to continue to plan the seismic programme and work with the Ministry of Economic Development to turn the application into permits. The seismic acquisition is subject to financing, most likely through a farm out of the permit, and the positive conclusion of local appeals and operational approvals.
The group has also drafted an appraisal well EIA submission for the Giove oil discovery, to be submitted during 2016, to drill a well 12 to 18 months after submittal, again subject to financing and approvals being received. All offshore permits are currently held in suspension pending approvals for the next state of the work programmes.
In December, the Italian government passed a law restricting offshore oil and gas activities within the 12 nautical mile limit off the coast of Italy. Most of the group’s offshore acreage is unaffected by this law change but one application is fully within the 12 mile limit in the Ionian Sea, and three applications are partially within the limit so they have received full and partial rejections early in 2016.
In the onshore acreage, in early 2015 the group agreed a farm out deal for the Cascina Alberto permit in northern Italy with Shell Italia whereby in return for an 80% interest in the license and operatorship, Shell Italia will carry the group for a seismic acquisition programme up to $4M and a single exploration well up to $50M. Shell Italia also paid the group $850K on completion of the farm out. The operator has commenced the exploration work programme with the reprocessing of existing seismic to determine if further data acquisition will be required before making a decision on an exploration well. A decision on seismic acquisition is expected in Q3 2016.
There was little activity on the French Guiana exploration permit during 2015 and it is due to expire in mid-2016. The joint venture is currently considering options regarding the future of the permit. There has been limited activity on the license in the Otway Basin in South Australia during the year. The license continue to be suspended to allow further technical work and evaluation prior to potentially progressing with a seismic programme. The group continues to seek a farm in for the license.
The group have taken further steps to reduce their general and admin expenses. This included relocation of the head office, staff reductions and reduced salaries for the board and senior management. During the year the group raised a total of £1.6M through a combination of a subscription by the group’s two key shareholders, raising £1.2M, coupled with an open offer to all shareholders raising a further £400K. The new capital allowed them to finalise the terms on the acquisition of the Rainbow assets and funded modest work programme for 2016 to deliver growth in Canadian production.
An impairment loss of $2.1M has been recognised against the costs capitalised in respect of the Sicily Channel licenses CR146 and CR149. These licenses are currently under suspension awaiting EIA approval to drill a well. The carrying value of the permits in the southern Adriatic has not been impaired but if no progress is made during 2016, the board will consider whether the carrying value is still warranted. An impairment loss of $970K has also been recognised against the Australian cost pool. The government of South Australia has agreed to place the license into suspension to allow time for a farm out to be completed once the short term economics improve. Given the uncertainty of timing and likelihood of a farm out being completed the directors have decided to impair the cost pool in full.
In addition there were $621K impairment losses in the year relating to accounting and procurement IT systems implemented in early 2012. Following the decision of the directors at the end of 2015 to implement a Canadian software package and migrate the group’s accounting and procurement onto that system, the carrying value of the existing IT system has been fully impaired. The 102/11-30 well encountered the reservoir on prognosis but problems experienced when cementing the liner over the reservoir section lead to difficulties in interpreting the well test. The well delivered nearly 100 barrels of oil per day during the test with 85% water production but it was not possible to determine where the water was coming from due to the cementing issue. As a result the well was suspended pending a subsurface review to understand the water production mechanism and determine the optimum way to produce the well with minimal water production. Due to the uncertainty surrounding the economic value of the well, the directors impaired its carrying value by $2.5M.
As of the end of march, the group had just $700K of cash with $1.4M on deposit from the Alberta Energy Regulator which is forecast to be returned from June this year, although there is material monthly revenue being received with production currently over 400 bopd which at an oil price of about $50, all group costs would be covered. The continued oil price volatility and relatively small financial resources of the group at this time mean that the focus over the next will be on sourcing further capital to increase production, most likely via debt finance or an asset farm out in Italy.
While the group has no material capex commitments, the cash position combined with the future revenue from existing oil and gas fields, is only likely to provide enough financial resources to undertake the redevelopment work programme in Rainbow and Virgo planned for the first half of 2016. Any further development or drilling in Canada and appraisal activities on the assets in Italy will require external capital which may come from the farm out of existing assets, debt or equity. Also if the group suffers operational difficulties, it may not have the financial resources, even if the oil price increases, to resolve whatever operational problems have arisen and would be forced to seek further capital from external sources.
On the 6th April the group released an update. Net oil production in March was 432bopd which equates to sales for the month of about 13,400 barrels. Three additional wells will come on stream in April following completion of the workover programme and the 9-25 battery is waiting for regulatory approval before start-up which will initially add another three producing wells. Near term production will support the return of the $1.4M abandonment deposit paid to the Alberta Energy Regulator in January which is now forecast to be returned in three monthly payments starting in June.
Following the completion of the winter programme, a summer work programme will be developed for August and September to achieve further production enhancements and operating cost synergies. The company is now receiving material monthly revenue from the Rainbow assets and production engineering and subsurface reviews conducted to date have identified significant opportunities to steadily grow production from this assets base with relatively low capital investment and risk so the company is now focused on developing plans to realise these opportunities.
Overall then, this has been a very difficult year, as it has been for many small oil and gas producers. The loss did improve from last year, even when we take out the large impairments in 2014, as the group cut costs. Likewise, although the cash outflow from operations increased year on year, this was due to a large payables payment and the cash losses actually fell. Still, the group burned through $11.5M in cash before financing. The net asset level also took a battering during the year.
The group started the year with all of its wells shut in as they were loss making in the current climate. The group also suffered a technical failure in the only new well drilled, and a problem with a third-party pipeline. As the year progressed, some production was brought back on stream as some costs lowered and the pipeline issue was sorted. The addition of the Rainbow assets was an essential step too, which meant that by March 2016 the group was producing 432bopd.
Italy has been placed on the backburner somewhat but the farm out with Shell is a good step in the development of at least one of those assets. The amount wasted on the old IT system is very disappointing, however. The group now only has $700K in cash and despite the fact they should get their deposit back from the Alberta regulators later in the year, it seems inevitable that they will have to raise more cash. Hopefully this will come from a farm-out but this is by no means certain and it is a distinct possibility the company will have to undergo another dilutive placing to keep the lights on. Not something I am willing to risk a bet on at the moment.
On the 10th May the group released a production update. Net average oil production in April up to the 18th was 449bopd but regional trucking restrictions were imposed for the rest of the month due to the expected annual spring thaw which meant that production from wells tied in via a pipeline continued at a rate of 212bopd and overall average production for April was therefore 354bopd. The trucking restrictions were lifted by the 29th April due to unusually dry weather so trucked wells are now back in production.
The 9-25 battery is ready for start-up once final approvals are obtained from the regulator which will add another three producing wells. Costs incurred to date at the Rainbow development project indicate that operating costs per barrel are between $20 and $25 when measured at an average production rate of 400bopd. The variable operating costs per barrel of incremental production over 400bopd are forecast to be between $4 and $10 per barrel, depending on whether the oil is transferred to the processing facility by pipeline or truck.
Following the completion of the current programme, a summer work programme will be developed for Q3 to achieve further production enhancements and operating cost synergies. Building production from here will create an asset with very attractive net cash flow, even at current oil prices.
On the 7th July the group released an update. The workover programme on the Rainbow assets consisted of the reconfiguration of tank storage and pipelines at two single well batteries; the replacement of tubing, rods and pumps in five wells; and the re-testing of pipelines and re-certification for use with the AER. The cost of the programme was budgeted at more than $1M but with adjustments and a reduced cost environment, the same production target from 150bopd to 400bopd was achieved at a total cost of about $500K.
There are eleven producing wells tied into 13-36 and four single well batteries currently in production whose output is trucked into this facility. The 9-25 battery is about 25km to the SE of this battery and currently has three wells tied into the facility and on production. Following processing and water separation, dry oil is stored at the facility before being trucked to the 13-36 battery for sale. The produced water disposed of at 9-25 is used in a waterflood programme to bring pressure support to three additional wells that are awaiting pipeline reinstatement before being brought online.
In the Virgo area, the 15-23 well is tied in to the local operator’s infrastructure. Produced oil, water and associated gas is piped for processing, separation and sale by the local operator. The average production for May and June, during which there were unusually heavy rains was 300bopd due to trucked wells being shut in as road conditions restricted the trucking of oil to the 13-36 battery for sale. With roads repaired and all wells on production, net average production for the last week in June was about 500bopd.
The focus for the proposed Q3 work programme is to improve operating synergies and costs and increase production through the restart of three waterflood wells at the 9-25 facility. One of the largest costs in this field is electrical power, which is used for pumps and the processing facilities. Within the Rainbow asset ate 16 sweet gas wells which are connected to the 13-36 facility and have about 700K standard cubic feet of daily production capacity. This is sufficient to provide more power than is currently required by the assets and the company is evaluating the possibility of installing gas powered generators to produce electricity from this supply.
There are three wells connected to the 9-25 battery which are shut in due to the pipeline needing some repair work. These wells receive the benefit of the pressure support from the waterflood programme. Subject to confirmation from engineering studies, the company is planning to repair and test the pipeline this summer and bring the wells back into production.
While the 9-25 battery is located about 25km from the 13-36 battery, the nearest point between each facility’s connected pipeline network is only 3km. The group has commissioned studies to assess the cost and work required to connect the two facilities which is anticipated to have significant operating cost savings and reduce production downtime due to trucking restrictions in bad weather.
There are between ten and fifteen further well workover candidates from the existing well inventory which should require only the pulling and replacement of rods or pump assemblies to bring them back into production. Alongside this work, the company is considering a list of reefs in the Rainbow area which have had limited oil recovery and could support further production from a sidetrack well, drilled from an existing well. Material production gains could be possible from this activity with relatively low risk and limited capital outlay, especially in the current cost environment.
The final activity being considered for a winter work programme is the recompletion of some of the wells in the Virgo region. The original plan for these wells was to tie them into local pipeline infrastructure for transportation and processing of produced oil and water by the local operator. The 15-23 well was completed this way and is on production with a tariff being paid to separate and disposed of produced water as well as process the oil for sale.
Given the third party tariff paid for this work, the lower sales price achieved for oil in Virgo and that the company now owns its own processing facilities in Rainbow, they are considering the recompletion of these wells without connecting them to the local infrastructure. This would allow the separation of oil and water at the well site and disposal of produced water downhole to a lower formation through a dual completion assembly. Dry oil could then be trucked to the 13-36 facility where it would receive a better sales price and not incur third party tariff.
The increase in production from the Rainbow assets to 400bopd, combined with the rise in oil price since February is providing material monthly revenue and cash flow. The next step for the company is to increase production further and not only cover group costs but to create net operating cash flow for future investment. With the initiatives discussed above, I am feeling for the first time that the company might actually make it.