Petroceltic International Plc is looking to sell a further 18.375% stake in Ain Tsila gas field in Isarene Production Sharing Contract (Blocks 228 and 229a), Algeria. Earlier in April 2011, Petroceltic farmed out 18.375% interest in the Isarene Production Sharing Contract (Blocks 228 and 229a) to Enel Trade. Continue reading here..
There are 20 opportunities recorded in Derrick’s “Deals in Play’” database for the region of North Africa comprising Algeria, Egypt, Morocco, Mauritania and Egypt.
Out of these 20, 12 opportunities are for stakes in exploration blocks previously awarded, 5 are opportunities relating to developing undeveloped discoveries, 1 is for a stake in a producing field and 1 is for stakes in multiple asset types (appraisal/pre-development discoveries & 1 producing field) (Map 1)
Figure 1: Map of North Africa with locations of opportunities shown by colored circles. Circles are colored based on the asset type. Place cursor over circles for additional information on the opportunity. Click on circles to get detailed opportunity break down (pop ups need to be allowed).
The maximum opportunities are in Morocco (8), followed by Tunisia (7), Egypt (3), Algeria (1) and Mauritania (1).
Derrick has valued the following packages (developing discoveries & producing fields) - (Table 1)
1. Dana Petroleum offers 25% in exploration concession offshore Egypt
2. Roc Oil to divest package of assets offshore Mauritania
3. Canamens Energy seeks farm-in partner(s) for two licenses offshore Morocco
4. Atlas Petroleum and Eurogas seek farm-in partner for Sfax permit, offshore Tunisia
5. Cooper Energy to farmout interest in offshore Tunisian field
Table 1: Derrick valued deals are shown with their asset types (transaction type), deal value and country. Squares are colored according to hydrocarbon type. Place cursor over squares for additional information on the opportunity. Click on circles to get detailed opportunity break down (pop ups need to be allowed), asset information and deal value.
North Africa presently accounts for 29% of total opportunities present in Africa
Cook Inlet, the channel that runs from the Anchorage area south to the Gulf of Alaska, is home to Alaska's oldest producing oil and gas basin. Cook Inlet has attracted explorers since at least the last century. From as early as the 1800’s, oil seeps were noted along the Gulf of Alaska, and the search for oil continued into the 1900’s, and does so now into the 21st century.
Figure 1; Map of the Cook Inlet showing the prominent oil and gas fields. Source, modified from Kenai Burrough.
The first attempts at exploration occurred in the 1900’s when six wells were drilled between 1900 and 1906, although without success. Exploration continued through the 1900’s without much success until the late 1950’s. The first commercial oil discovery was made at the Swanson River Field in 1957. This discovery became a focal point for oil and gas exploration and also helped Alaska achieve statehood by showing that Alaska could support itself through resource development revenues instead of being a drain on the Federal government. The first and largest commercial gas discovery was made at the Kenai Field in 1959. This was followed by the largest oil discovery at the McArthur River Field in 1965. Exploration drilling peaked in 1966 and between 1964 and 1968, 14 offshore platforms were installed. The Steelhead platform was installed in 1986 and the final was Osprey, installed in 2000. Following the discovery of the giant Prudhoe Bay oil field in 1968, the focus of exploration in Alaska shifted to Prudhoe Bay. This discovery was in a sense detrimental to exploration efforts in the Cook Inlet region. The Cannery Loop and Pretty Creek gas fields were discovered in 1979 and were the last commercial gas discoveries. The West McArthur and Tyonek Deep (Sunfish) oil fields, discovered in 1991, were the last major oil discoveries. This area has produced a cumulative total of over 1.3 billion barrels of oil and 7.3 trillion cubic feet of natural gas. However, Cook Inlet natural gas production has been steadily declining with current production at approximately 190 Bcf per year.
Figure 2: Chart showing exploration drilling in the Cook Inlet since 1950, with number of wells. The prominent discoveries are highlighted.
According to the USGS in 2011 "The Cook Inlet Region of Alaska contains an estimated mean of 19 trillion cubic feet of natural gas, about 600 million barrels of oil, and 46 million barrels of natural gas liquids, according to a new assessment by the U.S. Geological Survey (USGS). This estimate is of undiscovered, technically recoverable oil and gas resources, and includes both unconventional and conventional resources.These gas estimates are significantly more than the last USGS assessment of southern Alaska in 1995, in which a mean of 2.14 trillion cubic feet of gas was estimated. This increase in the undiscovered resource is attributed to new geologic information and data."
THE ECONOMICS – HOW GOOD IS GOOD??
Investing in exploration in the Cook Inlet region has become highly attractive after the state passed the House Bill 2001, known as Alaska’s Clear and Equitable Share (ACES) in 2007. ACES was designed to develop and promote drilling activities in many of Alaska’s untapped locations. The program essentially de-risks the process of drilling off shore in Alaska, by providing companies with generous tax incentives to develop existing resources in the area. Production in Alaska has been steadily declining over the last few decades and the State is aiming to ease its increasingly high energy demand. ConocoPhillips and Marathon Oil in February announced that they will close their liquefied natural gas plant in Kenai, which has been the single largest user of Cook Inlet natural gas, due to their inability to renew their contract with Japanese customers. Although there is enough gas in the North Slope of Alaska to meet demand in Cook Inlet, that would entail constructing a massive pipeline over the State, which would cost many billions of dollars. A summary of the incentives offered to explorers is given below.
1. Cash Rebates – Companies get the following rebates
a. A 65% cash rebate against all exploration, appraisal and development drilling, and seismic expenditures.
b. A 45% rebate towards all development costs (flow lines, platforms, etc)
Companies can recover upto 65% of these rebates 6 – 12 months after expenditure or well completion.
Special incentives to facilitate the movement of a jack-up rig to the inlet, to hasten gas exploration because of steeply rising demand.
2. Incentives to hasten the movement of a jack-up rig to the inlet
a. 1st operator receives 100% (upto 25M) of well cost including mobilization and some jack-up rig modifications.
b. 2st operator receives 90% (upto 22.5M)
c. 3rd operator receives 80% (upto 20M)
These credits are only available for the first 3 wells drilled with a Jack-up rig to Pre-Tertiary region and includes rig mobilization costs. Only one credit can be awarded to each company and if hydrocarbons are successfully found, 50% of the tax credit must be paid back from the producer to the States over a period of 10 years; there is no repayment necessary if a dry hole is drilled.
IS GOOD, GOOD ENOUGH?
Some companies are taking full advantage of these tax credits to develop and explore their acreage. Buccaneer Energy, a junior oil and gas company, has been attracted into drilling in the Cook Inlet based on these attractive fiscal policies. The Australian Company, Linc Energy, also drilled the first wildcat gas exploration well in the region in 5 years and drilling operation continue at present. However, it remains to be seen if any of these wells drilled using state sponsored rebates will be commercially successful. If these wells turn out to be commercial finds, it would undoubtedly lead to an increased interest in the Cook Inlet and propel some of these junior exploration companies, exploring in the area, to the big leagues.
Table 1: Table showing the companies planning exploratory drilling in 2010 and 2011. The number of columns have been minimized to fit the table on the page. The actual database has many more parameters listed and recorded. Source, Derrick Petroleum- Planned Exploration Wells Database.
NOTE:Buccaneer Energy was successful with their first well drilled in Q2 2011 in the Cook Inlet; the Kenai Loop-1 well. The Kenai Loop-1 well encountered up to 16 zones totalling 510 feet of gross pay identified by logs as test candidates in the Beluga and Upper Tyonek Formations. In the initial phase of the testing program, the Kenai Loop # 1 successfully tested gas to the surface at a rate of 10 million cubic feet per day on a 20/64” choke with a FTP (flowing tubing pressure) of 3,495 psi. Buccaneer's expectations have been exceeded!! More to follow as drilling progresses!
Sonatrach will launch a pilot project for developing unconventional gas resources in 2012 in Algeria.
According to company sources, Sonatrach is ready to go in to it alone if they don’t find a partner. Algeria supplies about 20 per cent of Europe's natural gas , but Algeria has under-invested in new oil and gas projects. It normally takes between five and eight years for shale gas projects to come on line. Sonatrach plans to invest US$46 billion in upstream activity in the medium term.
ENI is looking into Algeria's shale gas opportunities, an executive at the Italian company said Wednesday, making it one of the first international companies to signal its interest for North Africa's unconventional resources.
The interest is also part of a broader strategic diversification within ENI. In December, it entered the European shale gas market with an acquisition in Poland.
ENI has entered shale gas development projects in Poland and the United States. The company has agreed to develop shale gas opportunities with China's PetroChina. It has said it is looking into unconventional resource development in North Africa.
BP has backed off from plans to sell assets in Algeria, The
surprise announcement also comes after Russian joint venture TNK-BP Ltd., which
is half-owned by BP, said Tuesday it was still interested in buying the assets
owned by the British company--the largest foreign oil and gas investor in the
North African nation.
Earlier this year, BP agreed to sell its stake in the two fields, which each have production of up to nine billion cubic metres, for $3 billion, but the government's decision to withhold the data has led to speculation that it is interested in snapping up the assets for itself.
It is not the first time the Algerian government has intervened - in 2000, it blocked BP's proposed sale of a 40% share in the Rhourde El-Baguel field to energy giant Elf, opting to exercise its pre-emptive right of purchase.
A major blow to the
potential Russian buyer TNK BP
While confirming its interest in the BP Algerian assets,
TNK-BP had cautioned it didn't expect a breakthrough in negotiations soon.
Algeria's state energy firm, Sonatrach, had signaled an interest in exercising
a right of first refusal to the BP assets. Separately, TNK-BP's Russian
shareholders are in a dispute with BP over the possible participation in an
Arctic deal signed by the U.K. company with Russian oil company OAO Rosneft. It
is unclear if the spat affected the Algerian considerations.
Asset portfolio in
Algeria
In Algeria, BP has two large natural-gas projects, In Salah,
which covers seven fields in the southern Sahara desert, and In Amenas. BP also
participates in the Rhourde El Baguel oil project, and is exploring for oil in
the Bourarhet block next to In Amenas.
