Northern Petroleum has now released its interim result for the year ending 2015.
When compared to the first half of last year, revenues fell by $908K to just $223K. Cost of sales also fell, representing the fixed level of costs incurred during the shut-in period in addition to the cost of shutting the wells in and an element of the work undertaken to restart the 100/16-19 well, to give a gross loss some $651K worse than last time. We also see a $1.6M decline in admin expenses and an $814K “other” operating income relating to the cash received for the farm out of the Cascina Alberto permit, which meant the operating loss was $2.1M, an improvement of $1.9M year on year. We do see a foreign exchange loss of $429K due to the strengthening US dollar though, which drove the loss for the first six months of the year to $2.6M, an improvement of $1.2M when compared to the first half of 2014.
When compared to the end point of last year, total assets fell by $8.9M driven by a $9.2M collapse in cash, a $1.9M decline in exploration and evaluation assets and a $1.1M fall in receivables partially offset by a $3.6M increase in oil and gas assets. Total liabilities also fell during the year, mainly due to a $4M decline in payables. The end result is a net tangible asset level of $4.6M, a decrease of $2.7M over the past six months.
Before movements in working capital, cash losses improved by $1.5M to $1.6M but after a large fall in payables as the group paid down a significant amount of Canadian creditors, the net cash outflow from operations was $4.5M, a $1.9M deterioration year on year. The group then spent $3.9M on property, plant and equipment relating to the capex on the 102/11-30 well drilled in February and the tie-in of the 102/15-23 well, along with $560K on exploration and evaluation so that before financing the cash outflow stood at $9M. There were no financing items so this was the cash outflow for the period which meant that the cash level at the period-end was just $3M.
In Canada, production from the group’s existing wells was shut in towards the end of January. They were being produced using expensive rental equipment and production was being trucked, making it only marginally economic before being tied into local infrastructure. With the drop in the oil price, only one of the wells was tied in as the capital payback period on the investment required to tie in the other wells had significantly increased. Following the temporary halting of production, the rental equipment was removed from the remaining wells and the ongoing running cost of the operations in the field was reduced to as low as possible.
Subsequent to shutting these wells in, the operator of the infrastructure detected a problem with part of their pipeline network, requiring 102/15-23 to be shut in as well. This meant that for the majority of the period the group had no production. Economic production was restarted in June from the 100/16-19 well, enabled by the purchase of a low cost production vessel that removed the need for high cost rental equipment. Production from the 102/15-23 well was expected to restart during Q3 but the operator of the local infrastructure is undertaking a wider review of the pipeline network following initial repairs and the restart of production will occur after the infrastructure operator makes the necessary repairs or the group implements an alternative offtake solution.
During Q1, the 102/11-30 well was drilled into a previously developed reef. It 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 suspending pending a subsurface review to understand the water production mechanism and determine the optimum way to produce the well with minimal water production.
Significant progress has been made in Italy. The group farmed out an 80% interest in the Cascina Alberto permit to Shell for a cash contribution of $850K and a carry effectively through to the end of the drilling of any exploration well on the permit. The group has also received the approval of six environmental impact assessments in the Southern Adriatic, one for the proposed 3D seismic programme across the Giove oil discovery and Cygnus exploration prospect, and five others for application areas. Approval for these EIAs allows the group to plan the seismic programme and work with the Ministry of Economic Development to turn the applications into permits.
Further reductions in cost have been made during the first half of the year including an additional reduction in the number of staff and an office move to a much more cost effective location. With just $3M in cash at the period end, a number of initiatives are actively being pursued to bring necessary further capital resources into the group to find the business. With the outlook for crude oil prices remaining uncertain into next year, the focus of the business is on minimising the cost of development and production.
Overall then, much like many similar small oil and gas companies, this has been a difficult six months. The total loss did improve but net assets declined and the operating cash outflow increased due to the payment of some large Canadian creditors – the underlying operating cash loss actually improved year on year. Still, with a cash burn of £9M and just £3M left in the bank, the group will likely need to raise more funds from somewhere. The Canadian operation has had a very difficult half year with problems in the pipeline network and expensive rental equipment meaning that there was practically no production at all during the period. There is no one well back into production but that is not going to carry the company. Things in Italy progressed rather better with the farm-out agreement and the EIA approvals.
Overall though, until the funding issues have been clarified and the oil price improves this seems like a very difficult company to invest in so I will wait on the side lines.
This is not a good looking chart!
On the 12th November the group announced a proposed direct subscription of 40,000,000 new shares to raise $1.2M, an acquisition of assets in NW Alberta and a proposed open offer for up to a further 40,000,000 new shares at 3p per share.
The acquisition comprises of existing production facilities and wells on mineral leases across approximately 28,000 acres, the majority of which are in the Rainbow area of NW Alberta, about twenty miles South of the company’s existing Virgo assets. The consideration to be paid is about $200K in cash and the company will also assume the abandonment liability for all the wells and facilities acquired, with the net liability estimated at $1.5M. The operating cash flow attributable to the assets being required was C$400K over the past eight months.
These Rainbow assets were previously acquired by the vendor as part of a larger corporate acquisition and were regarded as non-core. They are estimated to contain proved and probable reserves of approximately 1.185M barrels of oil equivalent with a calculated net present value of about $14.7M. The existing wells on the leases were drilled to target multiple reservoir horizons including a Devonian Keg River light oil play, the same play as targeted within the company’s Virgo assets. The Rainbow assets had average reported production in September of 211boe/d, of which about 80% was oil.
The assets include a total of 117 operated and 41 non-operated wells, of which about a third are either currently in production or are believed to have the potential of being brought back into production. The remaining wells are either suspended or abandoned. In addition to the wells and mineral rights, a material amount of facilities and equipment are included with the acquisition. There are two main facilities which consist of storage tanks and water separation facilities as well as water disposal wells. There is also a direct sales point into the Plains Midstream Pipeline system for produced oil. These facilities will provide operational synergies for the existing Virgo assets, since production can be trucked, processed and sold through the Rainbow Assets facilities without incurring third party processing and water disposal fees currently being paid by the company for its existing production.
The directors have identified an initial work programme on the assets which is proposed to be initiated shortly after the completion of the acquisition. This involves the reinstatement of wells and facilities and is intended to double the existing oil production over the next year. It is forecast that this production, combined with the forecasted production from the company’s existing assets, will provide sufficient net cash flow to broadly cover their total general and admin costs in 2016, using an oil price of $47 per barrel, and should allow the company to access the debt capital markets for future development capital. Over the long term, it is believed that the combined asset base could support production growth to in excess of 2,500 bopd.
The company has raised £1.2M before expenses via a subscription of 40,000,000 shares at an issue price of 3p per share. It is being taken up by Cavendish Asset Management and City Financial Investment, both existing shareholders. Also, a further 40,000,000 shares will be made available at 3p per share under the terms of the open offer to raise a further £1.2M which the directors at least intend to take up.
As far as operations are concerned, in Canada since the end of Q2, the 100/16-19 well has continued to produce with a water cut of about 25%. Average daily production for Q3 has been about 25bopd. Well 102/15-23 is still not producing as the owner of the pipeline has decided not to proceed with the repair that is needed so the company is looking at undertaking the repair itself.
In Italy, the exploration work programme has begun on the Cascina Albert licence, which involves the reprocessing of existing seismic to determine whether further seismic is required before a decision can be made on an exploration well. The company is now planning a work programme to acquire 3D seismic in the southern Adriatic across the Cygnus exploration prospect and Giove oil discovery, which is forecast to occur in Q3 2016. This seismic acquisition is subject to financing, most likely through a farm out of the permit, and the positive conclusion to local appeals and operational approvals. The company is also drafting an appraisal well environmental impact assessment submission with the plan to drill a well in the next year and a half.
They aim to drill five wells in five years across its Italian permits and exploration applications, each with the potential to add material value to the company upon success. The completion of such a forecast programme will be subject to securing suitable financing and all the necessary regulatory approvals. The company has ongoing discussions with various third parties in the industry regarding possible farm outs of its Italian assets and is currently in discussions with one particular party concerning the farming out of its offshore permits and exploration applications.
The directors and other key management have agreed to further reduce their salaries. In exchange for this reduction, nil-cost options over new shares will be issued every three months so that they don’t miss out – so we are swapping dilution with costs then, and given the current value of the company, this could be substantial. Things have got so dire here that they are having to reorganise the capital of the company as the new shares are being issued at a price lower than their nominal value.
This really is a desperate situation here. The group only has one well currently producing, the owner of the pipeline is refusing to repair the damaged section and now up to 80,000,000 new shares are being issued compared to a current total of 95,365,660, meaning huge dilution, for a paltry £2.4M which, hopefully, will bring the company up to a break-even position. I am glad I don’t own shares here, it is a shame really as some of these Italian assets do look potentially interesting but I don’t see this company as investable at the moment.
On the 22nd January the group released an update. At the year-end the cash position stood at $2.4M after the payment of the consideration for the Rainbow assets and other year-end payables. The forecast for 2016 general admin costs is less than $3M and positive cashflow is forecast from Canadian production, even in the current oil price environment.
The focus in Italy over the next six months will be on the submission of an environmental impact assessment for the approval of an appraisal well to be drilled on the Giove oil discovery in 2014; planning for a 3D seismic acquisition in the southern Adriatic in the second half of 2016, primarily over the Cygnus exploration prospect; and the ongoing exploration campaign on the Cascina Alberto permit for which the company is being carried by the operator Shell.
Both the proposed 3D seismic over Cygnus and the appraisal well on Giove will require external funding and the company is in discussions with several companies to understand if appropriate funding can be structured for the programmes. In addition to these activities, the company awaits the final decree from the MOED for the award of five exploration permits which adjoin the existing permits in the Southern Adriatic.
In Canada, following the payment of the cash consideration for the acquisition of the Rainbow Assets the Alberta Energy Regulator has assigned the leases to the company following the deposit of $1.2M. This deposit represents the cost of the asset abandonment liability as due to the shutting in of production during last year, the assigned asset value has steadily decreased which has resulted in a larger cash deposit being made than initially forecast. The deposit will return to the company once production and asset values increase which is expected to occur as a result of the winter work programme.
Canadian production from the enlarged company currently totals about 200boe per day, of which about 80% is oil. In total the proved plus probable reserves come to 1.48M boe of which proved reserves are 0.92M boe. The winter work programme focuses on the replacement and repair of pump and rods and engines on the Rainbow Assets as well as returning the previously shut-in 09-25 battery into production.
In the Virgo area, the 102/15-23 well has been shut in for nearly a year due to a pipeline integrity issue on a third party operated gathering system. After discussions, the company has agreed to take ownership of the affected section of pipeline and carry out the necessary repair work during February to bring the well back in to production.
There is no drilling or well workover activity planned for this winter. Due to the oil services industry adapting to the changing industry environment and a further refinement of the programme, it is anticipated that this work programme will now cost about $600K, almost half as much as originally forecast and will take about three to four months. The company now expects this programme should lead to a doubling of their production.
On the 15th March the group released an update covering the Canadian business. The recently acquired Rainbow assets are performing better than expected. There are initial high rates of production as wells are restarted and the asset base appears to have plenty of scope to reach the target of 400 barrels per day this year.
The winter work programme targeting the doubling of group production to 400bopd began in late January following the acquisition of the Rainbow assets. The programme is focused on restarting wells through the replacement and repair of equipment, storage tanks and pipelines at both those assets and the nearby Virgo assets. To date, the group has acquired and tested the pipeline tie-in from the 15-23 well to the local operator in the Virgo assets area; reconfigured the facilities and pipe work at 15-1 in the Rainbow Assets area; and pressure tested and prepared for the reinstatement of the 9-25 battery in the Rainbow Assets area.
It is anticipated that the 9-25 battery and the majority of the wells tied into that battery will start production later this month and the battery also has the benefit of third party tariff income derived from the processing of other operators’ oil.
The remaining activity of the programme involves the use of a rod rig and workover rig to change out broken rods and pumps on up to six wells, which will then be restarted. The amount of wells included in the programme will depend on the timing of the arrival or warmer weather. A further well, 2-12, is also being considered as a start-up candidate subject to reconfiguring the facilities at the well head.
The capital cost of the programme is expected to be within the reduced forecast cost of $600K. The company has already deposited about $1.3M with the Alberta Energy Regulator as an abandonment deposit when the new assets were acquired. This money will be returned to the company once the deemed asset value increases above the abandonment liability. The company expects the full deposit to be returned during Q3 this year and the capital cost of the programme and a possible further summer programme will be managed around the timing of this deposit return.
The 15-23 well, which produced for less than a month at the beginning of 2015 before being shut in due to problems with the pipeline tie-in, was bought back online at the end of February at a rate of 540bopd with very little water cut. It has now been choked back to produce between 100 and 150 bopd to help minimise water production over time.
The 15-1 well, which has been shut in since 2012, when it was producing about 20bopd, came back into production towards the end of February at almost 400bopd. It was then shut in following problems with the well head equipment, which was repaired, and is now back in production at a restrained rate of between 100 and 150bopd, again to minimise water cut in the longer term.
The 13-36 battery continues to produce at approximately 140bopd from eight tied-in wells. Production from 15-1 and 9-25 will be trucked to the battery for processing, water disposal and sale into the Plains Pipeline System.
A priority for the company is restricting the initial high rate flus production, which in turn should reduce the rate at which the water cut climbs. This is not as important for those wells directly tied in via a pipeline to the 13-36 or 9-25 facilities as both have water disposal wells, but increasing water cut from standalone single well batteries means increased trucking costs to transport produced oil and water to the batteries for processing and sale. This is also the case for the 15-23 well where the company has to pay the third party operator processing fees for water separation. The longer term plan for all the wells is to ensure produced water can be disposed of at minimal cost, allowing these wells to produce oil profitably even when the water cut is in excess of 90%.
Overall then a nice little update that shows some progress is being made in Canada but it would have been nice to have received some information about the cash position.