Fast pre-salt flow rates (peaking around 26kbpd on average) and low offshore decline rates (just -8.8% / year) were two drivers of high well productivity that we observed in our recent overview of 14,000 wells and 300 fields drilled in Brazil over the past decade. Overall, Brazil’s wells are more productive than other offshore basins we have analysed. In particular, the Santos basin pre-salt appears the “best of the best”, with the most productive wells of all: notably Lula’s Cidade de Angra dos Reis FPSO reached its design capacity around 90-100kbpd with just four (of six planned) wells connected & producing (Exhibit 1, Exhibit 2).

Drilling times are also declining, with the best composite wells’ drilling times likely to be 75% shorter than the first pre-salt wells. The discovery well at Lula took 141 days to drill, the average presalt well this year took 75 days, the best well took just 43 days and the best composite future wells could be drilled in just 34 days (Exhibit 3). At this rate, you could conceivably drill the c4-5 producers and 2-3 injectors required to bring on a new FPSO easily in a year with a single rig.

Will Petrobras have enough rigs after the cancellation? – We think so. Petrobras currently has 17 deep water rigs in operation in the pre-salt Santos basin area. At peak, we model that 30 wells per year must be drilled at the key five BG fields, which could imply as little as four rigs per year are required (assuming no improvement from 2012 drilling rates and a week-long turnaround to move rigs between well-sites). Even with other wells to drill in the Santos, this looks comfortable, given 17 rigs currently present and 28 further rigs under contract to be delivered over the remainder of the decade.

Pre-salt economics continue to look strong, between $5-9/boe, potentially stronger if fewer wells are required. We model an average NPV per barrel of $6.7/boe across BG’s pre-salt fields. Our numbers include c300 wells across these five super-giants, over their lifetimes. With each well costing $100M including drilling, subsea, risers and their connection to the FPSOs, the potential savings are there, albeit smaller in the context of the $160Bn of gross value locked in these five fields today.

All major states require the filing of a drilling permit before the drilling of a well. The filing for the permit is usually one of the last steps taken before drilling. Before the permit is filed for, companies incur significant expenses, including land costs, legal fees, and geological expenses, and, at that time, much of the infrastructure is in place. Thus, most well permits that are filed for are drilled. Barclays extensive analysis shows a strong relationship between drilling permit issuance and rig count. While lead time varies by cycles and states, most often it is roughly two months.

Drilling permits for the 30 states that Barclays monitors increased 0.5% in September 2012, following a 18% rise in August. Barclays believes permit activity reflects a return to normal permitting conditions following summer seasonality and indicates the early stages of a trough in the North American land market.

Offshore permits

The Bureau of Ocean Energy Management (BOEM) issues permits for offshore wells drilled in the GOL on a rolling basis. BOEM permit announcements tend to lag contract awards for the offshore drillers typically by a couple of weeks. However, offshore permit issuances are one of the final steps prior ro commencement of drilling operations and help to indicate future offshore activity levels.

Barclays believes the deepwater rig counts will surpass pre-moratorium levels by year end and reach 45-50 by 2014. In September, the BOEM issued 13 total permits for floating rigs in the US GOM, down from 25 permits announced in August and 27 permits in July. There was one new well permit issued in September (down from 3 in August) and 11 revised new well permits (down from 19 in August). Of the 13 permits issued in September, 11 permits were for exploratory work and 2 were for development jobs. Exploratory locations (shallow water adn deep water) in the GOM stand at 32, up from 26 at year end and 23 locations this time last year. Despite the dip in permits issued in September, Barclays believes permit activity in the US GOM remains healthy and suggests a continued imprevement in the permitting process, which was stifled following the Moratorium. We believe the floating rig count in the US GOM is set to increase further as more deep water rigs are delivered and migrate to the region.

The BOEM issued 28 shallow water permits (including 3 for new wells) in the US GOM in September, down from 34 in August ( 7 for new wells) and 40 in July (3 new).

The mechanics of onshore production are fundamentally different from offshore production. The largest 25 fields off Norway today were developed with 110 total wells per field on average; the largest 25 fields in the Gulf of Mexico were developed with 30 wells on average; while typical Russian fields of the same size (in kbpd) required 1,080 wells to develop: an order of magnitude higher, reflecting lower well production rates of 400-600bpd (versus 2.4kbpd in Norway and 9kbpd in the GoM deepwater).

Russian onshore fields have a “sluggish” production profile, typically taking a decade to ramp up to peak. It takes 6-7 years to recover half of the oil from the average Norwegian / UK field. A “peaky” GoM field can recover half of its oil after 2-3 years. But in Russia, it takes as long as 20-years to recover
half of the oil at a typical field, based on the production profiles. Because of the time value of money, these “sluggish” production profiles yield 40% lower NPVs per barrel than offshore production profiles. We estimate undeveloped Russian oil resources are worth $0.7/bbl when fiscal terms are considered.

Forward-looking Russian decline rates are likely to be higher than the past, at -3.5% on average. Russian fields’ decline rates accelerate as the fields mature. Today the weighted-average barrel in Russia is produced from a field that has been in production for 30-years. Only 12% of production is from fields in their first decade of production (when production typically ramps up) vs 30% two decades ago. Incorporating this higher decline rate from very mature fields in our oil market models would subtract 0.5Mbpd of supply by 2015 & 0.7Mbpd by 2017 and increase oil price forecasts by 5%. Our 2017 Russian forecast, at 9.7Mbpd would be 0.85Mbpd below the IEA’s recently updated estimate, using this decline rate assumption.

The History and Maturity of Russian Onshore Production
Russian oil production ramped up to 11.4Mbpd at peak in 1987-8 according to the BP Statistical review, and fell precipitously after the collapse of the Soviet Union, before a reorganization of the upstream industry in the late 90’s and early 2000’s recently restored output to a new high: 10.4Mbpd this year on average (Exhibit 1). Although Western Siberia is the largest component of Russian output today, at c70% of the total country’s production, its ramp-up took-place mostly in the 1970s as Pre-Caspian and Volga- Urals production matured and declined. Today, West Siberia is in decline, while recent growth has been driven by greenfields and increased production in East Siberia, Timan-Pechora and the Far East.

Therefore the increase in Haynesville production was not so much to do with new wells being drilled, but
more the backlog of wells available for completion that had already been drilled (Exhibit 12). While a
(greatly shrunk) backlog still exists, its current level could likely sustain flattish production for only an
additional few months without new drilling.

With the backlog almost fully eroded and only ~20 rigs now drilling in the play, the chance for material
declines in the December or January timeframe remain a distinct probability, potentially to the tune of ~200 mmcfd a month (referring back to Exhibit 9 – but noting that absolute declines decrease as the overall production base falls).