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 21^st 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. 1^st operator receives 100% (upto 25M) of well cost including mobilization and some jack-up  rig modifications.
              b. 2^st operator receives 90% (upto 22.5M)
              c. 3^rd 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.

Source: Derrick E&P Transactions Database

Try this free document search tool

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.

Try this free document search tool

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.

Source: Derrick Petroleum E&P Transactions Database

Range Resources Q1 output up on Marcellus Shale drilling; Targeting Marcellus to be self-funding 2013 and capture full resource potential

Natural gas company, Range Resources Corp reports increase in its Q1 2011 production as the company focused on drilling the liquids-rich portion of the Marcellus Shale play in Pennsylvania and the Midcontinent regions. The company's production volumes up 17% to 545.5 mmcfepd, and they are on track to produce 400 mmcfe by the end of 2011. Range says by the end of 2012 they will be producing 600 mmcfe. Due to the outstanding performance of its existing wells combined with the initial performance of the newly connected wells, Range's Marcellus production has temporarily outgrown the existing infrastructure.

Range Expects the Marcellus Division to be a Value Driver for the Future
The Marcellus now appears to be the second or third largest natural gas play ever discovered in the world.  With the benefit of a large, liquids-rich window in southwestern Pennsylvania, the Marcellus offers the best economics of any large-scale, repeatable play in the US.  A significant portion of Range's acreage also offers the benefit of natural gas potential from the Upper Devonian and Utica shale formations that lie above and below the Marcellus.  In 2011, Range is directing 86% of its capital budget toward development drilling in the region.

Range has ~550,000 net acres in the SW part of the play. Over 800 wells have significantly de-risked 460,000 of Range’s acres. Assuming 80 acre spacing, and that 80% of this acreage will be drilled, this equates to 4,600 wells. The resource potential is for the Marcellus and does not include any potential from other shale zones. Utica and Upper Devonian shale wells have been completed and are currently waiting on pipeline connection.

Range is giving up 113 mcfe a day of natural gas production capacity with its 52,000 acre Barnett Shale sale. The $900 million Range gets for Barnett, coupled with cash flow and another $200-250 million in expected non-core asset sales this year, not only funds 2011 Marcellus development but also carries $400 million forward for 2012 development. Couple in 2011 and 2012’s development and production growth and Range expects 2013’s capex will be funded solely from its own cash flow.

Key Marcellus Deals in 2010 and 2011

Source: Derrick Petroleum E&P Transactions Database
Try this free document search tool

EOG Resources sells $647 million worth assets in US. Another $400 million worth assets up for sale. Where could it sell?

EOG Chief Executive Officer Mark Papa disclosed that EOG had sold $647 million worth assets in its goal of divesting $1 billion worth of assets this year. He added saying, “In the first quarter, we received $260 million from asset sales. Since March 31, we've received an additional $387 million of proceeds and we're actively working on an incremental $400 million of sales.”

The sale that was subsequent to the first quarter included all mature gas-producing properties in South Texas and New Mexico. The major portion of that was some Cotton Valley production, Cotton Valley/Travis Peak production in the East Texas area.

The M&A activity of EOG in 2011 is captured as follows-

Source: Derrick Petroleum-E&P Transactions Database

Try this free document search tool

Where could the other $400 million sale be focused??

The operations map of EOG is as follows 

• Mark Papa, CEO of EOG resources, in 2010 Earnings Results Conference Call disclosed that the company is considering to sell Niobrara acreage depending on what price is offered. With the oil prices increasing gradually, this would be the best time to reap the benefit by selling Niobrara acreage.

OR

• EOG is growing as an oil focused company by shifting their focus to oil. EOG’s revenue mix in 2008 was 29% to oil and 71% to gas, whereas the forecasted production mix for 2011 is vice versa- 29% to gas and 71% to oil. The recently clinched $647 million sale of gas weighted assets is also in line with EOG’s transition from gas to oil. Therefore, EOG might end up divesting certain non-core gas assets in US and Canada (contribute 90% of EOG’s gas reserves) to stick with its new strategic plan.

Source: EOG Resources 2010 Annual Report

Macquarie Tristone advises Suncor Energy on the sale of gas weighted assets in North Peace River Arch region. Package could be worth $115-$130 million. Suncor shifting focus to oil.

Suncor Energy Inc has engaged Macquarie Tristone to seek proposals for certain assets located in the North Peace River Arch region. Suncor’s Peace River Arch sale assets are focused in two separate areas:

• Boundary Lake - Primarly gas and associated liquids from various stacked large OGIP Permian, Triassic and Cretaceous reservoirs; Vertical development upside potential
• Parkland - Dominated by the large OGIP Parkland and Doe Wabamun gas fields; Stacked uphole Triassic and Cretaceous upside potential.

Suncor strongly favours a single bid for all assets but will consider offers on the individual areas identified. The highlights of the offering are as follows:

• Total current production of approximately 3,208 BOE/d (92% Gas-weighted) primarily from Devonian Wabamun, Permian Belloy and Triassic Halfway formations
• Reserves effective 31 Mar 2011: Proved reserves - 6,479 MBOE; Reserve Life Index of 5.5 years and NPV10- $79.5 million
• Proved + Probable reserves - 8,791 MBOE, Reserve Life Index of 7.5 years and NPV10- $105 million.
• Net Undeveloped acres: 8,052  acres
• Includes operated gas plants at Boundary Lake (~80 MMcf/d capacity) and Parkland (30 MMcf/d capacity).
• Proposals are due early to mid June 2011.

A quick analysis on the value of the package-

- The NPV model reports the value of the package could be $105 million.

- The industry metrics of $35,000-$40,000/flowing boe and $200-$250/acre values the package between $115-$130 million.

Based on both the valuation methodologies, the value of the package could be in the range of $105-$130 million.

Another gas weighted package from Suncor Energy worth $175 million is up for sale. The snapshot of the deal is as follows.

Source: Derrick Petroleum E&P Transactions Database 

Suncor's 2011 outlook- Shift focus to OIL

Source: Suncor Energy- May 2011 Investor Presentation

Suncor's 2011 outlook is to divest natural gas weighted assets with production of 37,000 boe/d (worth $1.5 billion based on $40,000/ flowing boe) and increase the oil production from 50% to more than 90% after the targeted gas divestitures. Suncor joins the "Marathon Run" of shifting focus to OIL.

The following table shows the 2010 gas divestitures of Suncor Energy-

Try this free document search tool

WILL ALBANIA BE THE NEW EXPLORATION HOTSPOT?

The Republic of Albania lies in south eastern Europe. It was under communist rule, but the communist party collapsed in 1990 and the Republic of Albania was formed in 1990. In the last decade Albania has evolved into a stable parliamentary democracy in a modern free market economy with a regulatory environment structured to attract foreign investment.

Figure 1: Location Map of Albania (Shown in thick blue). Source, modified from Google Earth.

EXPLORATION IN ALBANIA
The petroleum industry is one of the oldest industries in Albania, dating back 2000 years when the Romans mined bitumen. In modern times, exploration kicked off during the First World War when oil was discovered in Drashovica. Later in the 1920’s, the Patos Marinza (largest onshore oil field in Europe) and the Kucova fields were discovered with help from Italian investments. World War II led to a decline in output. The 1948 production was 1374 kboe, during which time the erstwhile Soviet Union began to play an important role in the industry (up until 1961 when Albania broke ties with the Soviet Union, and China starting playing an important role). Maximum production was achieved in 1974 with 17380 kboe annually, and Albania broke ties with China 4 years later. In 1989, total annual production was 7900 kboe and in March 1994 it was 3749 kboe. This decline was in part due to poor economic policies, lack of materials and natural decline. In 2001, it had declined to 2379 kboe. According to the CIA world factbook, total annual production in 2010 was 1971 kboe.

BIRTH OF MODERN EXPLORATION

The ultra- Stalinistic rule of the Enver Hoxha regime up until his death in 1985 plagued the Albanian economy, but after the collapse of the Soviet Union through the late 1980’s and the death of Hoxha in 1985, the Albanian economy opened up and culminated in the country adopting democracy in 1990.

The country’s first offshore licencing round was held in 1990, with contracts taken up by international companies, including Deminex, Chevron, Occidental, Hamikon and AGIP. This was followed by the first onshore round in 1992 which offered access to seven onshore blocks, won by a French company called Coparex, a Croatian company called INA Naftaplin and Shell.  In November 1994, a foreign investment law was enacted to attract and protect foreign investment, guard against nationalization or expropriation of assets and allow funds to be freely transferred in and out of the country. The second onshore licensing round in November 1995 was attended by 30 oil companies. The offerings were two onshore blocks not awarded in the first licensing round, eight new onshore blocks and one block in the Adriatic Sea.

OIL DISCOVERIES IN ALBANIA

There have been many discoveries in Albania and there are also a few fields producing. These are listed in the following table

Table 1: List of Oil/ Gas fields along with their discovery year, reservoir depth, API gravity and sulphur content. Source, Technological Institute for Oil and Gas, Albania.

Figure 2: Licenced exploration areas in Albania. Source, Manas Petroleum

SHELL AND COPAREX DO THE DIRTY WORK
Shell and Coparex spent a great deal of resources in acquiring and interpreting over 4000 km of seismic data over their onshore licences. The result of their seismic imaging and analysis was the recognition of a deep underthrust structure (~ 4 km deep) which according to them had the potential to host  820 mmboe. This same giant underthrust structure which hosts all of Albanias hydrocarbon reserves was also present below their licences in the form of a giant anticline. However, after all this good work, Shell and Coparex decided to abandon their licences due to conflicts in the neighbouring Kosovo and due to extreme unrest within Albania. This, as it turns out, was a boon for Manas Petroleum which later acquired these properties with giant, well defined, drill ready prospects.

THE ECONOMIC X-FACTORS
Although not recommended as a destination to spend an annual vacation, Albania has all the key elements to ensure a good return on investments through oil and gas companies active in the area. The key factors are:

1.        Location: - Excellent access to European markets 

2.       Stable political environment 

a.       Constitutional Democracy since 1991

b.       Member of WTO, regional and European trade organizations

c.        NATO member

d.       Currently undertaking key steps to become EU member (applied in June 2009)

3.       Hydrocarbon rich

a. Albania is home to the largest onshore oil field in Europe (Patos Marinza; 7.5 billion barrels OOIP)

b. Multiple active oil fields

4.       Favourable economics (for the number crunching analysts)

a.        Attractive terms

b.       10 - 15% royalty

c.        50% profit tax

d.       100% cost recovery

e.       Hydrocarbon law allows 100% export of crude oil

f.        100% cost recovery & working interest

g.       25 year term + 5 year extensions

Figure 3:  Comparison of petroleum exploration and production  contracts between different countries. As can be seen, Albania ranks quite high in terms of financial and profitability.

THE ACTIVE PLAYERS
Fortunately, for number crunching analysts, there are a few players within Albania actively pursuing exploration and production. These companies along with their assets are listed below:

1.        Bankers Petroleum Ltd. is a Canadian-based oil and gas exploration and production company focused on developing large oil and gas reserves in Albania. The Company operates and has 100% interest and rights to develop the Patos-Marinza heavy oil field (7.5 billion barrels OOIP; 140 million barrels produced to date; 6º to 24º API Oil), and has a 100% interest in the Kucova oil field (297 million barrels OOIP; 24 million barrels produced to date; 14° to 22°API Oil). It also has interests in the Block F Exploration Acreage consisting of 185,000 acres with gas and oil potential.

2.       Stream Oil and Gas has a 100% working interest in  3 producing heavy oil fields (Ballsh, Cakran, Gorisht) and the Producing Delvina gas field with 3 sister structures in phase II exploration 

3.       Petromanas Energy Inc. has 3 production sharing contracts (“PSCs”) comprising  6 onshore blocks, a 100%  working interest in Blocks A,B,D,E,2 & 3 comprising 1.7  million net acres, and have 9 existing oil fields on blocks 2 & 3 which include the largest onshore oil field in Europe, Patos Marinza which is operated by Bankers Petroleum Ltd.

4.       Cairn Energy through its subsidiary holds a 100% interest in the Joni-5 PSC  which is valid for seven years from 9 September 2007. 

5.       San Leon Energy and Beach Petroleum have a 75% and 25% interest respectively in the Durresi Block which lies in the Adriatic Sea, offshore Albania and covers an area of approx. 4200 sq km. It contains the A4-1X gas condensate field, discovered in 1993, 30 km off the southern coast of Albania.

Figure 4: Figure showing possible export routes for oil produced in Albania. There are about 15 refineries in the Mediterranean that can process Patos-Marinza crude apart from the other oils that are produced in Albania. Source, Bankers Petroleum. The favourable location of Albania would make it very easy to transport the crude for refining and then for supply into thirsty European markets.

OK… SO WHO’S DRILLING AND WHEN??
The Derrick Petroleum- Planned Exploration Wells Database keeps track of the number of wells being drilled globally and sorted by operator, country, oil or gas, year of drilling and many other parameters. From this database, the number of wells planned to be drilled in Albania in 2011 are 4. These four wells to be drilled will be significant as 3 of these wells are to be drilled by Petromanas on the almost drill ready, giant prospects, that were mapped by Coparex and Shell before they abandoned their plans. The upside is huge, and the results of these wells have the potential to change the face of exploration in this small Mediterranean country. The latest discovery in onshore Albania was made by Occidental Petroleum on the Shpiragu discovery after the Shpiragu-1 well in the Sqepuri  subthrust structure located in Block 2 proved oil from the Eocene – Cretaceous fractured reservoirs. The result of the Shpiragu-1 well have seriously de-risked this area. Gustavson and associates commenting on the probability of success on the Petromanas Blocks state "The probability of success for a wildcat well in a structurally complex area such as this is relatively high due to the fact that it is in a structurally favorable area, there exists a proven hydrocarbon source and analogous production exists only 20 to 30 kilometres away”. These few players have the potential to strike it big in Albania. With favourable economics and easy access to refineries and markets, the country presents a good deal to companies wanting to invest.

Table 2: List of companies with plans to drill in Albania in 2011 and beyond. 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.