Iona's Drilling program For Massive production growth.
Iona Energy has two developments in production with plans to develop three additional projects over the next 3-4 years. Production, which is estimated to average 7,000 boepd in 2014, is expected to climb to 13,000 boepd in 2016 and 21,000 boepd in 2017. That is a threefold increase over 3 years.
Cash flow generation based on the plan will be sufficient to fund capex and cover repayment of the secured bonds. Assuming successful execution of the current development program the expected cash generation from operations through 2017 less capex and debt servicing costs will result in over US$150 million of cash at YE 2017 in excess of funds needed to repay the balance of the bonds outstanding.
Discounted valuation. Iona trades at a steep discount of 75% to our 2P NAVPS estimate of US$1.85 ps (fully diluted). Furthermore the EV/DACF multiples of 2.3 times this year and 1.9 times next year’s estimates are the lowest within the peer group (average of 4.5 times 2014 and 3.1 times 2015). We believe the market is according a significant discount for execution risk. Delivering on the program will significantly de-risk the company’s developments and drive the share price closer to NAV.
Additional upside beyond our 2P NAV. The company has identified additional prospective and contingent resources at Huntington, Trent & Tyne and Ronan & Oran which have not been incorporated into our NAV or valuation. In aggregate the unbooked resource potential equates to over 100 mmboes or over US$1.25 per share of incremental NAV. A portion of these unbooked resources will be tested at Tyne early in 2015.
Target conservatively set at C$1.00. Our target is based on employing a 50% discount to our 2PNAV reflecting the risk of potential unexpected delays in the development timeline and possible cost overruns. As the company rolls out its development program we believe the shares will trade at or even exceed our conservative target. Even at our $1.00 target the shares are trading at a lowly 2015 EV/DACF multiple of 2.8 times. We are initiating coverage with a BUY Rating.
Iona is focused on developing and producing oil and gas in the UK North Sea. The company was formed in 2008 and has grown to an asset base with two developments in production, Huntington in the Central North Sea and the Trent and Tyne (T&T) natural gas fields in the Southern Gas basin. In addition the company has other projects targeted for development within the next four years: Kells, Orlando, West Wick and satellites to T&T plus a possible additional development at Ronan & Oran. With the exception of West Wick and the T&T satellites all the proposed developments are in close proximity to the Ninian platform in the Central North Sea. Iona also operates over 85% of its UK assets. Figure 1 illustrates the locations of the company’s producing assets and planned developments. Figure 2 illustrates the production and cfps outlook through 2017.
The company’s current production capability is in excess of 8,000 boepd and is expected to rise to over 20,000 boepd by late 2016 when Orlando and Kells are targeted to be on stream. Average production over the period will be less as operations will experience downtime from time to time due to scheduled maintenance activities and likely unplanned outages that are often tied to the harsh operating conditions in the North Sea. The company’s 1P reserves are 21.1 mmboes and on a 2P basis resources are 40.2 mmboes.
The Iona team lead by Neill Carson has a track record of successfully developing fields in the UK North Sea coupled with an in-depth knowledge of the basins. This execution experience will prove key as Iona rolls out its company operated developments over the medium term. The company’s operational team is located in Aberdeen while the company’s head office is in Calgary.
Late last year the company raised US$275 million in a senior secured bond issue at 97.5% of par which is callable in whole or part by Iona at any time. The proceeds were used to retire debt obligations with more onerous terms. Also the bond payment schedule provides greater flexibility to enable the funding of the next planned developments through Orlando, Kells and possibly Ronan and Oran. The key terms include; 1) an annual coupon of 9.5% payable semi-annually, 2) repayment commencing March 31, 2016 initially at US$41.3 million every six months with a final payment of US$68.8 million at maturity on September 30, 2018, and 3) covenants including a liquidity requirement which requires restricted cash and cash equivalents held of at least US$30 million. Under the bond agreement capital expenditures are limited to assets within the borrowing base (currently Huntington, Trent & Tyne, Orlando, Kells, Ronan and Oran). Also a working interest of at least 50% must be maintained in Orlando and Kells and no sale or disposal of an ownership in Huntington shall be permitted during the term of the bond as long as any call options are outstanding under a BP Structured Energy Derivative.
The company has tax pools of US$331 million with no expectation of incurring any current taxes until 2017 or later. Based on the company’s planned development program, a flat oil price of US$100/bbl for Brent and a natural gas price at point of delivery of US$10 per mcf the company will generate more than sufficient cash flow to fund the capex program, pay servicing charges and pay down debt. As illustrated in Figure 3 by YE 2017 cash is estimated at over US$350 million which more than covers the US$193 million remaining to be paid on the bonds. The key will be successful execution. Timing delays, cost overruns and/or a large contraction in commodity prices will impinge on the company’s ability to generate cash and repay the bond.
Huntington (17.55% economic interest)
Iona holds a 15% working interest, a 0.75% Disproportionate Lifting Entitlement and a 1.8% royalty interest equating to a 17.55% economic interest. Iona acquired its interests from Carrizo in December 2012 (February 2013 closing) at a cost of US$203.6 million.
Booked 2P reserves net to Iona are 4.6 MMboes (4.1 mmbbls oil and 2.6 Bcf of gas) and production commenced in April 2013. A number of startup issues have been encountered but peak production rates of 34,500 boepd were reached in September 2013. The company expects stable production rates in excess of 35,000 boepd (6,140 boepd net) through 2015.
The field is in 90 m water depth and was developed using a leased standalone FPSO. The total cost of the development was GBP344.6 mm and four wells contribute to production from the Paleocene Forties reservoir. The field currently produces light oil (43 degree oil) and a small portion of natural gas. We estimate operating costs are approximately US$20 per bbl and the current operating netback is over US$80 per bbl.
The company and its partners have identified additional upside to reserves and production in the lower Jurassic Maxwell and Triassic Skagerrak reservoirs. In the Northern segment (INA-15%) a well drilled in 2007 tested 39 degree API from the Maxwell formation at up to 4,600 bopd. Iona sees the opportunity to develop the Maxwell in a phased approach as capacity becomes available in the Huntington facilities. In the Central area (INA-15%) and the Southern area (INA-100%) further upside potential also exists. Iona and its partners plan to submit a Field Development Plan to conduct engineering work with a first oil target date in 2016.
The company’s reserve auditors have identified unrisked contingent resources of 24.0 mm bbls gross (3.6 mmbbls net) and 46.7 mmbbls gross (7.0 mmbbls net) of prospective resources for the deeper potential at Huntington
Trent and Tyne (100% – includes recent purchase of a further 80%)
Trent and Tyne are two producing gas fields in the Southern gas basin. A 20% interest was acquired in 2011 while the balance (80% interest) is planned to be acquired from Perenco for US$20 mm. Closing is anticipated in October 2014 with an effective date of January 1, 2014. Reported 2P reserves at 100% W.I. are 46.7 Bcf or 7.8mmboes. The 2P NPV (at 10%) is US$161 million and production capability is estimated at 25 mmcfd (4,166 boepd).
The Trent and Tyne fields are two separate unmanned platforms. The fields have been in production since 1996 and are mature. Tyne has 5 producing wells (2 offline) and Trent has 3 producing wells (1 offline and 1 suspended). Platform infill drilling is planned for early 2015. The plans include drilling the Tyne T1Z Sidetrack next year (75% CoS).
The company believes significant untapped potential remains in the vicinity to be developed. The company has identified three drill ready opportunities in the near term that could add to overall reserves. The company plans to drill a well in early 2015 at a cost of approximately US$30 million to test an undrilled North West fault block (Tyne North West prospect) with an estimated 20 Bcf of prospective resources and a 58% CoS. If this well is successful the company will then target a well to test an extension of the fault block with potential reserves (company estimate) of 26 Bcf and a 68% CoS. Also the company plans a well to test an extension of Tyne West (50 Bcf of potential reserves and 64% CoS) and a well to test a terrace to the east of the Trent field (40 bcf of contingent resources and a 60% CoS). All wells will be drilled from existing platforms and if successful can be tied-in quickly. In our modelling we have included modest drilling success for these prospects in our forecast.
In the operating envelop of the Tyne field, and in particular the T6 well, salt deposition in the wellbore tubulars is a significant risk to production. It is a well-known issue in the gas fields of the UK Southern Gas Basin and elsewhere with highly saline formation waters. Standard industry practice is to install a water washing system to the wells. Fresh water is pumped down the wells which washes salt deposits to surface. A water maker takes seawater and, by reverse osmosis, generates fresh water for the water washing system. It is routine procedure to suspend production while the water maker is out of commission. Operational improvements to enhance the performance and reliability of the Tyne water maker are being implemented and should be rectified during the latter part of 2014.
Orlando (75%, operator)
The Orlando field is approximately 10 km northeast of the Ninian Central platform (NCP). The company initially held a 100% interest but sold 25% to Atlantic Petroleum in February 2013. Atlantic Petroleum also purchased at the same time a 25% interest in the Kells field. The field was discovered in 1988 and the discovery well tested 2,850 bopd of 32 degree oil on a restricted choke in the Ness formation. A successful 2 well appraisal program in 2011-12 confirmed reservoir quality and resulted in an upgrade to reserves.
Audited 2P reserves are estimated at 15.4 mmbbls (11.5 mmbbls net). A FDP has been approved and the company anticipates first oil in 2016 with a peak production rate estimated at gross 11,000 boepd gross (8,250 boepd net). Total estimated capex is US$151 mm.
The development plan for Orlando entails re-entering the suspended 3/3b-13z well, drilling a 3,000 foot horizontal producer, and completion with dual Electric Submersible Pumps (ESP’s). Additionally, a subsea pipeline, power supply and control umbilical are expected to be laid between the well-head and the NCP. Engineering modifications are expected to be completed at NCP allowing tie-in and first production shortly after completing the development well.
We have factored into our production forecast Orlando production starting mid- 2016.
Kells (75%, operator)
The Kells field is approximately 13 km southeast of the NCP. The company acquired a 100% interest in 2011 and subsequently pared that back to 75% through a transaction with Atlantic Petroleum acquiring a 25% interest.
Audited reserves are gross 8.8 mmboes (4.2 mmbbls oil and 27.5 bcf gas) or 6.6 mmboes net. The field was discovered in 1985, developed and produced 5.3 mmboes between 1992-94 before the field was decommissioned due to blockage of the pipeline (uninsulated pipeline) and low oil prices. In total 4 wells have been drilled into the reservoir. Expected peak production is 10,400 boepd (7,800boepd net).
A Field Development Plan (FDP) has been agreed to and held by DECC pending final submission in 2014. Kells is currently slated for development through the NCP following the tie-in of Orlando to the same facility. In our model we have assumed Kells commences production in the second half of 2016.
The Kells development plan comprises two subsea production wells, an oil pipeline, a control umbilical, and some pipework modifications at the NCP. Project activity will be phased through 2015 and 2016, with the company expecting first oil in the second half of 2016. A subsequent water injection project is planned to unlock additional reserves. This 2017 project will involve the laying of water injection and gas lift lines, and the conversion of the second well to water injection service.
West Wick (58.73%, operator)
Iona completed the acquisition of West Wick in 2012 at a cost of US$8.2 mm for a 58.73% working interest and operatorship in the development. West Wick is a heavy oil (17 degree API) field located 5 km west of the Captain field. The field was discovered in 1990. The discovery well was followed up with two appraisal wells. Audited 2P reserves are 16.5 mmbbls gross (9.7 mmbbls net) and possible peak production is estimated at 10,000 bopd gross.
West Wick is programmed for a three well subsea development. The development will likely comprise two producers powered by ESPs and one injector and will most likely be tied back to the offset Captain field infrastructure. However, Iona is also considering stand-alone facilities and is in consultation with its joint venture partner and supply chain and engineering studies are ongoing. The Company expects to select a development approach and submit the associated FDP in 2014 with possible first production in 2017. In our model we have assumed West Wick commences production after 2017 and outside our forecast horizon.
Ronan & Oran (100%, operator)
Since acquiring these two adjacent oil discoveries in the 27th licencing round, Iona has commenced reprocessing 270 km2 of 3D seismic data over the region, and has conducted more detailed subsurface mapping of Ronan & Oran that suggests the area of the discoveries may be greater than previously thought.
Three discovery wells all encountered oil down to the base of the reservoir without encountering an oil-water contact. Iona believes that subsurface mapping shows the potential to add significant resources which exists below known oil levels. A potential oil-water contact 150 ft deeper has been mapped out to the spill point lying to the northeast.
A preliminary appraisal location has been selected to penetrate and test the extension of this oil column deeper into the basin to determine the extent of these resources. The company estimates 2C contingent resources of 49 mmbbls and prospective resources of 22 mmbbls.
The reprocessed 3D data should be received in July, after which a final subsurface appraisal location will be confirmed. Iona is currently contemplating appraisal drilling in mid-2015, and has initiated permitting, a site survey, and procurement of a semi-submersible rig to pursue this opportunity. Success with an appraisal well will move prospective and contingent resources to 2P reserves