BG’s Q1 2011 E&P Production hit by civil unrest in North Africa, flooding in Australia, and shutdowns in the North Sea; Will BG ramp up to achieve the Group’s long-term rate of 6-8% to 2020?

Natural Gas giant, BG has challenging first quarter for O&G operations. The group’s production for the period was down 5% from 61.3 mmboe to 58.2 mmboe over the same period last year. This is due to unrest in North Africa, flooding in Australia, an increase in UK tax and a shutdown in the North Sea. The North Sea's effect on the company was exacerbated by the temporary shutdown, largely for maintenance, of the Everest and Lomond platforms. This contributed to a 5% fall in production volumes. In Tunisia, the restart of the Hasdrubal plant was delayed, and in Egypt there was significant disruption to normal patterns of gas demand. In addition, production volumes in the quarter were affected by extreme weather conditions and extensive flooding in Queensland, Australia. However, BG pointed to advances in Brazil and the signing of two sales agreements in Japan as reasons to be optimistic.

BG’s Performance in 2010 compared to Peer Groups:




Try this free document search tool

HIGHLIGHTS of the Quarter:

Brazil

Production at the first permanent module on Lula Sul increased to some 25 000 boepd, and construction of the next two FPSO modules advanced to around 50% complete, in line with plans.

In April 2011, conclusion of a Drill Stem Test (DST) on the Guará Norte well (3-SPS-69) in Block BM-S-9 in the Santos Basin was done. The DST confirmed high productivity of some 6 000 bopd of light oil (approx 30° API) with flow rates constrained by test facility capacity.

In March 2011, successful completion of drilling on the Iara Horst well in the BM-S-11 concession in the Santos Basin. The well encountered good quality oil (28° API) in a thick reservoir section. Further evaluation activity continues.

In February 2011, a new discovery of oil (approximately 26° API) in Block BM-S-10 in the Santos Basin. The discovery well, known as Macunaíma, is located in a water depth of 2,134m, approximately 244 kms off the coast of Rio de Janeiro state. Further evaluation of the discovery continues.

USA

BG Group's shale gas operations continued to gather momentum, with 46 wells spudded and 22 drilling rigs operating in the Haynesville shale during the quarter. Seven wells were drilled in the Marcellus shale.

Tanzania

In April 2011, the company announced its third Tanzanian gas discovery. The Chaza-1 well is located in Block 1 approximately 18 kms offshore southern Tanzania in a water depth of around 950m. It is intended that a second drilling campaign will commence in late 2011.

Kenya

In March 2011, the company signed a Heads of Agreement with the Kenyan government to acquire a 40% equity interest in the exploration block L10A and a 45% interest in block L10B, subject to negotiation of Production Sharing Contracts. BG Group would operate both blocks.

India

In April 2011, a consortium led by BG Group (50% and operator), was identified as the qualifying bidder for an exploration block (MB-DWN-2010/1) offshore the west coast of India. The block is approximately 350 kms from the coast, covering an area of 7,963 sq kms and in water depths in excess of 2,000m. The award of the contract will be subject to final confirmation from the government of India and regulatory approvals.

Norway

In the 21st licensing round held in April, the Norwegian government awarded BG Group a 40% interest in and operatorship of licence PL599, located in the Norwegian Sea.

"We now expect modest production growth in 2011. The plans for a ramp-up in production in 2012 and 2013, as well as our 2020 goals, are unaffected and are supported by significant progress with our growth projects in Brazil, the US and Australia, as well as further exploration and appraisal success in Brazil and Tanzania.", Mr. Chapman,  BG Group’s Chief Executive added.

BG's Strategic Acquisitions in 2010 and 2011

Source: Derrick E&P Transactions Database

BP looks for acquisition opportunities in Brazil and Russia.. Plans to spend $20 billion in 2011.

“BP is looking to acquire stakes in Brazilian oil fields to increase the production in South America”, said Guillermo Quintero, president of BP's Brazil division, during a press conference. Guillermo added saying, "We can't reveal the names for strategic reasons, but we have two or three farm-in negotiation processes underway. We didn't come to Brazil just to continue what Devon started, Brazil is strategic for us."

Try this free document search tool

Capital of $20 billion set for 2011

BP plans to spend $20 billion to expand its operations around the world in 2011 and is looking to new areas including Brazil and Russia to increase the oil production. BP's assets in Brazil include 10 blocks. Only one of them is in production phase with output of around 25,000 bpd. Guillermo said BP's production in Brazil could reach 100,000 bpd, but did not offer a clear time frame for this.

Also, BP has plans to participate in Brazil's 11th bidding round to be held in September 2011, which will not include blocks in the coveted deep-water region known as the subsalt that is home to the country's largest oil discoveries.

Status of M&A activity in BRAZIL

Recently, BP received the final approval to complete the purchase of ten exploration and production blocks in Brazil from Devon Energy. In 2010, the Chinese were active acquiring assets in Brazil. In addition, Brazil's Mines and Energy Ministry is planning to include frontier areas in north and northeast Brazil in the highly anticipated round 11 for new oil and natural gas blocks. The round is also expected to include onshore and deepwater areas in mature basins, in addition to equatorial margin basins in the northeastern and northern regions.

The map shows the major 2010 deals in Brazil.

Source: Global E&P Transactions 2010 Review

Opportunities available in Brazil

Derrick Petroleum has aggregated all publicly announced properties for sale. Derrick’ Deals in Play is the most comprehensive data set of its kind in the industry. The following table shows the prolific opportunities available in Brazil.

Source: Derrick Petroleum E&P Transactions Database 

Though 2010 was a disaster for BP due to Macondo oil spill, 2011 seems like a progressive year for BP that has clinched the $7.2 billion alliance with Reliance and announced $20 billion capex for acquisitions in 2011. The following graph shows 2010 production and capex of BP compared with its peers.

Create your own report using this interactive tool.

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