Register for free to join our community of investors and share your ideas. You will also get access to streaming quotes, interactive charts, trades, portfolio, live options flow and more tools.
Register for free to join our community of investors and share your ideas. You will also get access to streaming quotes, interactive charts, trades, portfolio, live options flow and more tools.
Placement of development wells would depend on how they expect the reservoirs to change laterally and the potential drainage radius of each well producing well. A fair amount of G&G and engineering goes into the design and placement of each well.
A development/delineation well (well on a structure that has been already drilled) would not count against the obligations to drill exploration wells in Phase II.
Casing is set to allow the wells to be drilled deeper in order to control unexpected pressure changes and prevent hole collapse.
IF, IF, IF the company had an LC and defaulted, its likely the bank would seize some company asset, pay the default amount, and sell the asset to recover its payment. The company would then have remedied its default until it was called to make another payment.
As midtier said, this is all speculation.
Usually a bank would have a lien on hard company assets which could be forcibly sold, if necessary, to collect. They wouldn't take an exploration lease, which only has intangible value, as security for such guarantee. Additionally, SNP, as the majority participant, would have to approve any transfer to interest.
Krom, I just re-read your note....and I'm not sure to which "performance bonds" you are referring.
There is almost always a performance bond provided by the Operator/consortium to the government to insure minimum obligations are met. It is usually only a percentage of the expected cost of operations. Obligations have been met for Phase 1 and it is extremely likely that the STP has returned all bonds by now. I some cases, as Midtier suggests, the Operator will require weaker partners to provide it (Operator) with some form of guarantee that they can meet the obligations of the partnership. If such guarantee (LOC, escrow, etc) exists, when the party defaults, the Operator would present evidence of such default to the bank (or institution holding the guarantee) and the bank would pay the operator. If the guarantee were a LOC, then the institution would have a "lien" on the defaulting company's assets. And it could grow much more complicated from there.
With simple default, the defaulting party usually just has its interests divided up among the remaining parties.
I generalize since I don't know the specifics of their contracts. I don't know specifically how EHRC is treated either. When a party defaults, they usually have a limited amount of time to remedy the situation, which could include transferring/selling their interest to another party. This would have to be approved by the other parties. If no remedy is found, the defaulting party's interest is divided among the remaining parties. That same decisions are made with wrt entering into Phase 2. If some parties wish to continue and others do not, those that continue would assume the interest of those that withdraw, unless they can be sold or transferred to other interested parties.
True. These conditions would have to have been established when the Party entered into the partnership. I wouldn't say this is a standard provision unless there were concerns from the very beginning about the financial capability of the party.
Minority partners usually have financial obligations to both the government (owner of the license) and the Operator. Most governments require some form of performance bond or guarantee that can range for a small percentage to 100% of the anticipated cost of the work program to be conducted. The Operator collects and submits this guarantee on behalf of the Parties. The bonds are released back to the Operator once the work has been completed. The Parties also agree (by vote) on a budget for work that will be conducted in the license area by the Operator. The Operator then bills the partners their proportionate share of the work ~30 days in advance of due on a monthly basis. Billing and costs are reconciled in the subsequent month(s) on a continuous basis. Parties with small Working Interests usual have no power to influence the work done and are voted along in every action taken by the larger interest holders. If a Party falls behind by 30-90 days (depends on the contract terms), they are considered in default on their obligations. There are usually a limited number of remedies. A Party that defaults usually has their interest proportionately divided up among the "paying" remaining partners.
Hypothetically, if new information made another area outside your partnership look good, you might keep that information to yourself to prevent your partner from becoming your competitor for that other area.
China is a big importer of energy. I can only speculate but I would guess they would want to secure any hydrocarbons they could, oil or gas, for their own markets (China). It is more of a priority than making money.
TOTAL is a big gas player. Most big players are both oil and gas companies.
Gas is much more difficult to transport to a distant market than oil. The conversion to LNG for shipping is very expensive. Currently in North America, gas sells at a discount to oil due to the significant new (huge)resource base attributed to "shale gas". In the Far East, Korea, Japan and China pay a LNG "premium" vs oil. New LNG is coming on line in Australia and Siberia soon. The Chinese had no equity interest in those projects.
I'm stating the obvious, but its SNP doing all the work. I'm not sure what obligations they have to ERHC to share their findings, especially where information can be extrapolated to areas outside the boundaries of the partnership. Most commonly, the Operator charges its partners a proportionate amount of the cost for its staff and all third party expenses directly related to the operations. Paying partners, therefore, have rights to all work generated by the Operator. Partners also have the right to do their own work at their own expense (also common).
"Wet" is oil field terminology for water i.e. a non-economic resource.
I have no idea what work they are doing or how long it might take. Hydrocarbon systems are complex and because they lie miles below, making it is impossible to measure every variable that might contribute to the success or failure of a project. I do not know if they encountered wet reservoirs with gas. If they did, I just commented that that would add complexity and a little more uncertainty to the model unless some obvious reason for what they found was evident (like a fault, etc...). A successful hydrocarbon play requires organic source material, temperature (maturity), a migration pathway to a trap (structure with seal), and a reservoir. Failure of anyone component results in a dry hole.
Biogenic gas is a product of bacterial decomposition of organic material. Bacterial activity is limited by temperature, above a certain temperature, the bacteria are killed. It really doesn't have much to do with water depth but more so, the depth (because temperature increases with depth) at which the source (organic) materials are found. The thermogenic process which produces oil and gas, begins at temperatures higher than the "kill" temperature of most bacteria. The geochemical signature of biogenic gas is very obvious. It can not be mistaken for thermogenic gas.
Either the number of reservoirs encountered were less than what was anticipated or some reservoirs were wet i.e. non-gas. In a virgin area, the rocks to be drilled are "estimated" from the seismic data. The seismic data response is based on density contrasts between different rock types. Interpretations are made based on many, many assumptions of what these densities might be until actual measurements are taken via drilling results. In a virgin area like this, it would have been very surprising if they would have encountered exactly what they proposed they would find. It is very possible they found fewer reservoirs than they expected. Adjustments are then made to the seismic models for re-interpretation of the entire data set. If some reservoirs were wet and while some had gas, this would add more mystery and complexity to the exploration model.
If all that was found was biogenic gas, then I'm sure everyone is doing source rock and basin maturity studies to try to determine from where it originated and where the more mature (hot enough to generate thermogenic products) part of the basin lies. Then they would study the migration pathways of the basin to try to determine where such products would flow and target those areas for future exploration.
I thought the clearly stated that ONLY biogenic gas was found. Not true?
As I said in my response to you, telling half the story is manipulative and could even be criminal. I am not suggesting that is what they are doing.
Midtieroil ....I think you are right, no one was expecting to find biogenic gas. Why would you then want the company to not disclose such extraordinary (surprising) results? On the one hand, you fault them for disclosing the discovering biogenic gas while at the same time believe they are withholding the discovery of thermogenic gas and/or oil. If they are doing as you suggest, they could be easily be found out and prosecuted. The selective release of information could certainly leave them open to charges of stock manipulation, which is what I believe many here already believe.
Assuming the news releases are true, the discovery of biogenic vs thermogenic gas has important implications on the future exploration strategy and commercial value of these blocks and I believe deserves to be mentioned, for better or worse. I wish they had announced the discovery of billions of barrels of oil; unfortunately, it hasn't happened yet.
It probably takes close to 1 year to contract a rig and get in on location with all the necessary ancillary services need to drill. Unless the extension of Phase 1 is quite significant, it seems unlikely that a well could be drilled in this phase. If a rig were available on short notice, drilling an extra well in Phase 1 (above and beyond the obligations of that phase) can usually be applied to the obligations of the successive phase i.e Phase 2.
Biogenic gas (methane) can be feedstock for LNG. In fact, LNG becomes mostly methane as most of the heavier hydrocarbons are stripped out during the cryogenic process. The heavier hydrocarbons, however, have more caloric (energy) value and therefore command a higher price. Gas is usually sold based on its energy value i.e. btu/cubic foot . Since methane has the lowest BTU value of all hydrocarbons, it realizes the lowest market price. This makes economics for purely biogenic sourced LNG project commercially more difficult. Since the Chinese are most interested in securing energy for national security, I am hoping the poor economics of biogenic LNG does not deter them from development provided sufficient resources are found. If thermogenic gas and oil are found, things get much better. Since ERHC will have to pay for its proportionate share of development, the product price must be sufficient for it to make a profit on its development investments. If not, there will be significant conflict among the partners. Most production contracts do not allow for a party to commercialize its resources without the approval of its partners. I have suffered through such negotiations....not fun.
The presence of biogenic gas doesn't preclude the existence of thermogenic products, either gas or oil, nearby. There are many oil and gas fields where biogenic gas is found either in shallower reservoirs of the field, or nearby. I wrote a post several days ago regarding the anomalous juxtapositioning of Noble Energy's biogenic gas field offshore Ecuador with that of BPZ's oil and gas field only 15 miles away. Both fields produce from similar depth. Its difficult to explain biogenic/thermogenic distribution there. JDZ exploration is still in its infancy; even less is known about this area.
They may have seen many "gas" indications on the well logs in "at least 3 wells" but it is unlikely that every gas indication (zone) was tested. Without a test, one can not conclusively state that gas was discovered. There may have been zone(s) in a 4th (or 5th) well that were too thin or had other issues which deemed it not worth the expense to test. That could be the justification for their statement of gas in "at least 3 wells"
Biogenic gas is natural gas; it happens to be all methane.
Extending Phase 1 would allow them to do additional work without assuming the full drilling obligations of Phase 2. It also allows extension of the entire exploration phase of the blocks and postpones the (partial and complete) acreage relinquishment obligations common in most exploration contracts.
Haven't looked at the pressure info. What's critical to making reserves estimates is the profile of change in pressure during production i.e. a long term test. Obviously, if the pressure declines quickly, the reserves accessed by the well could be relatively small. Conversely, a slow pressure decline indicates larger recoverable reserves/well. Starting with high pressure is good because it permits quicker recovery....The recovery rate and volume are both key factors in determining the economics and commerciality of any project.
WRT biogenic and thermogenic gas....I have encountered biogenic gas in many locations around the world. Biogenic gas is generated in low temperature environments, temperatures not sufficient to create thermogenic gas and oil and/or to kill the bacteria that create biogenic gas. A very interesting example of co-location of bio-genic and thermo-genic products, however, is offshore Ecuador and Peru. Noble Energy produces a biogenic gas field from reservoirs 12-15,000' deep. This is abnormally deep (and hot) for biogenic gas to occur (I am not aware of any other occurrence >10,000). BPZ Energy, 15 miles to the south, produces 2 fields or oil & gas (a small % is biogenic) from the same depth. Geologically its difficult to explain why biogenic gas is found at such depth and adjacent to oil and gas. As an ERHC shareholder, I can only hope such mystery exists in the JDZ.
Full support w/450,000 shares
Although I hate to participate in these "conspiracy theories", it would be in SNP's interest to announce "conservative" results in order to reduce industry interest in the area for future bid rounds. A significant discovery would attract global attention and intense competition. Of course, this would not be in the best interest of the gov'ts offering the exploration rights, however, these gov't could be well compensated by direct Chinese gov't aid (to the countries and individuals) for any potential loss as a result of such "conservative" news releases.
They may be investigating mini-LNG and floating LNG processes for the gas. This would be among the first in the world if they went in that direction; very state-of-the art. Cheaper development scenarios reduce the economic threshold for development. The global LNG market is currently quite weak. The fact that this would be a Chinese asset, makes that almost irrelevant. They want their OWN gas and not have to be dependent of foreign suppliers. This might be one of the few advantages of having the Chinese involved.
I have never worked this area. I don't know how continuous the stratigraphy/reservoirs are on the Nigerian side and I do not know if biogenic gas is common here or not. Given that there are few nearby wells, none really close, I would believe they really had no any idea what they would find in terms of reservoirs or hydrocarbons other than from what could be suggested from seismic data. These were real EXPLORATORY wells (wildcats). I've seen others mention that they drilled to the minimum depth to fulfill their obligations. Since these were the first wells/block, it may have been a priority to meet the obligations as quickly (and cheaply) as possible. If they got lucky in the First Phase, great. If not, they have the option to continue. I believe they will (because big blocks with identified structures in hydrocarbon basins are extremely rare). Still, I am surprised that NO data was provided. Did anyone in the meeting ask for such???
Precisely. It would have been nice to see some INTERPRETED seismic and well data that showed what they were drilling (at the bottom), where the reservoirs were encountered, the seismic character of the reservoirs and of the (undrilled) deeper horizons, how they correlate structurally and stratigraphically to known hydrocarbon bearing intervals in other blocks/areas, how they relate to the remaining undrilled prospects.......I've given presentations to shareholders that have always included material information such as this.
I'm disappointed that no technical data (well logs, seismic lines over the locations, maps, cross-sections) were presented in order to put the results in perspective. Either SNP did not authorize such or ERHC didn't believe it was important to allow its shareholders (and others) to formulate their own opinions on how the results have changed the prospectivity of the assets, either for better or worse. Did I miss something?
I also believe this is the critical issue, no oil, and was the biggest surprise. At least I was surprised.
Fully expect SNP to continue into Phase 2. Its just too difficult to find large properties with identified structures and hydrocarbon indications. Exploration opportunities like this are rare. Plus they are committed to resource exploration/extraction from Africa.
Seismic data is used to identify structures. If enough information can be gathered regarding rock densities, rock types (and other info), it can sometimes be fine-tuned to "see" indications of gas. Oil and water do not have sufficient density contrasts to be distinguished. It works like an ultrasound. Its much simpler to get an clear ultrasound image because the precise densities, thickness and shape of the human body is known. When one explores with seismic data in a relatively unknown area, every variable necessary to create an image must be "guessed". With additional information (drilling, well logs, rock and hydrocarbons samples), the picture becomes more accurate.
Biogenic gas (pure methane) is a by product of bacterial activity. Biogenic activity only occurs below a certain temperature (i.e. this activity occurs at relatively shallow depths). The bacteria feed on higher chain organic molecules, that from which oil originates in a thermogenic process. The process required for generating liquid hydrocarbons requires higher temperatures (which kill bacteria). Therefore, biogenic gas is generated in a different location than that which generates oil. The occurrence of biogenic gas does not preclude oil deeper or at other locations. But it does mean that thermogenic products have not migrated to this exact location. Dry gas has less caloric value and, therefore, less $$ value than wet gas (higher caloric value) and liquids.
Gas caps are, by definition, at the "cap" (top) of the structure within a given horizon. One almost always drills the top of a feature first. Its possible that gas and oil can be segregated by depth in the structure and by drilling deeper in the same location, heavier hydrocarbons (liquids) will be found. Hydrocarbons can also be (and usually are) segregated within the same reservoir by depth. This mean its possible to explore for oil in these same horizons as they extend off the flanks of the structures. In effect, the reservoirs look like upside-down "U-tubes", with the lightest gas trapped on top and increasingly heavier hydrocarbons down the "legs" of the reservoirs. Extensive geophysical work would be done to determine if the "edge" of the gas cap can be identified. Below that point, oil might be found.
Marginal OR inconclusive with respect to oil. Reprocessing and updating of the rock properties model does, legitimately, take months. It is still very possible that SNP could/would make an offer to buyout ERHE once they are comfortable that real value does exist AND before they (SNP) release results or resource estimates. Only SNP would know if that's tomorrow, 6 months from now.....At that point, ERHE might either choose to accept or seek market valuations. Does anyone know if ERHE's carry includes the reprocessing of the seismic? I would assume so. I would expect SNP has a right-of-first refusal on any third party offers.
Thanks for the civil response. 300MMBO to be commercial is very big. Deep water Gulf of Mexico and Brazil fields are commercial @ ~100MMBO.
Commerciality is a risk valuation based on the future value of the reserves to be developed minus the capital and operating expenditure, royalties and taxes to be paid. Every oil company makes these estimates before the start an exploration program. The are continuously adjusted with every new piece of information. One needs an "estimate" of both sides of the equation to make this "determination". Without actual information, its impossible to value these assets, and by extension, ERHC.
I'm asking the question, what is needed to be "commercial"? Is there a volume estimate? Obviously, the higher the volume, the less likely the outcome.
remove the word "produceable"