Wednesday, May 11, 2011

Exploration in the Cook Inlet: A shot in the dark?



INTRODUCTION AND HISTORY
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!









Suncor Energy posts 6.5% Increase in Production for Q1 2011; Capital Spending was primarily on Expansion of In Situ Oil Sands Operations; Production In Line with company’s target of one million boepd by 2020


Suncor Energy’s upstream production in first quarter 2011 was 601,300 boepd, up 6.5% over same period last year. Suncor’s Q1 2011 production averaged 601,300 boepd, compared to 564,600 boepd during the first quarter of 2010.  Oil sands production was 322,100 boepd, 59% increase from the first quarter of 2010. Suncor, which is expanding its oil sands production and processing operations as part of a joint venture with Total, said it had seen higher oil sands production volumes and higher realized prices in upstream operations.

In March 2011, the company completed sale of non-core North Sea assets for proceeds of £105 million (US$ 170.44 million), subject to closing adjustments. The company secured two operated exploration licenses and one non-operated exploration license in the Norway portion of the North Sea in April 2011. In addition, the company is evaluating an exploratory well in the Ballicatters field offshore East Coast Canada.
Source: Derrick Planned Exploration Wells Database


Targeting One Million Boepd by 2020
Suncor continues to move forward on its ten-year growth strategy outlined in December 2010. In support of the growth strategy, capital spending in the first quarter was primarily focused on expansion of the company's in situ oil sands operations. In April 2011, Suncor began injecting steam into a Stage 3 well pad and expects to achieve first oil by early July 2011. The expansion is expected to be fully operational in the third quarter of 2011, with production volumes ramping up over approximately 24 months thereafter toward target capacity of 62,500 boepd of bitumen.

With the closing of its strategic partnership agreements with Total E&P Canada Ltd. on March 22, 2011, Suncor expects to progress with engineering and site preparation work for the Fort Hills oil sands mining project and the Voyageur Upgrader. Under the terms of the agreements, Total assumed an interest in both Fort Hills and the Voyageur Upgrader, while Suncor assumed an interest in Total's Joslyn oil sands mining project. Suncor is targeting the completion of the Voyageur Upgrader and the Fort Hills project for 2016.

Quicksilver Resources to sell HRB acreage for $150 million. Another $1.5 billion package in HRB is on the table.

Quicksilver Resources is considering seeking a partner for its Horn River Basin (HRB) acreage in northeastern British Columbia”, said Glenn Darden, President and CEO of Quicksilver, during the Q1-2011 conference call.

Source: Quicksilver May 2011- Investor Presentation

Quicksilver’s work program in HRB
Quicksilver completed its 2010/2011 winter drilling program in the Horn River Basin and has now drilled a total of eight horizontal wells into the Muskwa and Klua formations, of which four wells have commenced production (11.1 MMcfe/d for Q1, 2011). Only two additional wells are required to validate all of Quicksilver’s exploratory licenses and convert these licenses, covering approximately 130,000 net acres, into 10-year development leases. In addition, the company has drilled its first horizontal well into the shallower Exshaw oil formation and expects to begin completion activities on this well this summer.  


Status of midstream development in Quicksilver’s HRB asset
Quicksilver has initiated midstream operations associated with its Horn River assets. Construction and compression related to Quicksilver’s own 20-mile, 20-inch gathering line, which will serve as the spine of Quicksilver’s transportation from its Horn River acreage, is now complete. Final tie-in of the line into the Spectra system is anticipated in late May, which will enable the company to flow gas from its four completed gas wells at unrestricted rates of more than 30 MMcf per day.


It’s vital that a company has a strong midstream system in place to ensure it can process and transport its gas at reasonable cost and sell it for acceptable prices. With the midstream facilities in place and considering 25% sale or JV, the acreage to be sold can be valued between $130-$160 million (based on $4,000-$5,000/Acre).

The following table shows the other HRB packages (total worth $1.5 billion) put up for sale.

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