Analysis of Tank Emissions 

This discussion describes a revised estimate of tank emissions, as compared to the tank 

emissions in the current proposed rule. The proposed rule uses U.S. Inventory1 estimates 

of greenhouse gas emissions from crude oil and condensate stock tank vents. Based on 

partner experiences shared with Natural Gas STAR, it is believed that emissions from 

these sources are under-estimated. Due to insufficient data and time, EPA moved 

forward with the Inventory estimates in the threshold and burden analyses for onshore 

production. However, while finalizing the proposed rule, EPA combined previously 

published data from the Houston Advanced Research Center (HARC2) with newly 

obtained data from the Texas Commission on Environmental Quality (TCEQ3

) on tank 

emissions to independently estimate tank emissions and determine the potential effect on 

the rule. 

This independent estimate of emissions from tanks determined an increase in emissions 

over the U.S. National Inventory of approximately 26.9 million tonnes of CO2e 

(MTCO2e). This independent analysis is described in the appendix to provide detail on 

the analysis. 

The revised tank emissions estimates were input to the onshore production threshold and 

burden models and the results were compared to the current proposed rule. These are 

presented in Exhibit 1 below. 

Exhibit 1. Comparison of Proposed Rule Onshore Production Burden to Revised 

Tanks Case. 

Metric 

Proposed Rule (Onshore 

Production) 

Revised Tanks Case (Onshore 

Production) 

Total Emissions (combustion and 

process) 277.8 MTCO2e 304.7 MTCO2e 

Process Emissions Covered at 

25k tonne Threshold 154.9 MTCO2e 179.1 MTCO2e 

Emissions Covered at 25k tonne 

Threshold (%) 82% 83% 

Entities Covered at 25k tonne 

Threshold (%) 4% 5% 

Compliance Cost at 25k tonne 

Threshold $18.5 million $19.0 million 

Cost Effectiveness at 25k tonne 

Threshold $0.12/tonne $0.11/tonne 

While the total U.S. emissions estimate for onshore production increases by almost 10%, 

the cost-effectiveness improves by only 1 cent per tonne, from 12 cents to 11 cents per 

tonne, and the coverage of total emissions and entities only increase by 1% each: 82 to 

 

1

 EPA. U.S. Inventory of Greenhouse Gas Emissions and Sinks: 1990 – 2007. Available online at: 

<http://epa.gov/climatechange/emissions/usgginv_archive.html>. 

2

 HARC. VOC Emissions from Oil and Condensate Storage Tanks. October 31, 2006. 3

 TCEQ. Upstream Oil and Gas Storage Tank Project Flash Emissions Model Evaluation. July 16, 2009. 
83% and 4 to 5%, respectively. Thus, the anticipated coverage and costs of the proposed 

rule are not significantly impacted by this revised estimate of tank emissions. 
Appendix – Tanks Analysis 

Crude oil and condensate stock tanks are used to hold oil for brief periods of time in 

order to stabilize flow between production wells and pipeline or trucking transportation 

sites. To fill a field stock tank without using a pump, the gas-liquid separator is operated 

at high enough pressure to overcome flow-line pressure drop plus the head of a full stock 

tank. When the oil at separator pressure enters the stock tank at atmospheric pressure, 

light hydrocarbons dissolved in the oil—including methane and other VOC’s and 

hazardous air pollutants HAP’s, and some inert gases—vaporize or "flash" and vent from 

the fixed roof of the tank. As the liquid level in the tank fluctuates, and barometric 

pressure and temperature fluctuate, more light hydrocarbons vaporize and vent to the 

atmosphere (called “working” and “standing” losses, respectively). 

►U.S. Inventory Estimates

The U.S. Inventory recognizes that flashing emissions from tanks are not dependent on 

the number of tanks, but the throughput of hydrocarbon liquids in those tanks, 

characteristics of those hydrocarbon liquids (such as API gravity), the pressure and 

temperature of the equipment immediately upstream of the storage tank (typically a 

separator), and the temperature and pressure of the tank (typically atmospheric). 

For its activity factor, the Inventory considers the throughput of hydrocarbon liquids. It 

assumes that all produced condensate passes through storage and all crude oil produced 

from non-marginal wells (that is wells which have production rates greater than 10 

bbl/day) and 20% of crude oil that is produced from marginal wells also pass through 

storage tanks. 

Since a detailed database of separator temperatures and pressures as well as the 

associated hydrocarbon liquid characteristics is not available, the U.S. Inventory uses a 

set of 101 E&P Tank simulation runs developed by the American Petroleum Institute in 

the 1990s to estimate benzene and other hazardous air pollutant emissions from crude oil 

and condensate stock tanks. The speciation of emissions from these runs includes 

methane which was used to develop a methane emissions factor per barrel of 

hydrocarbon that passes through storage. E&P Tank software was specifically designed 

to provide an affordable alternative to more versatile software packages to estimate 

flashing emissions from hydrocarbon storage tanks. The 101 simulations, using field 

operating data, represent hydrocarbon gravities from 17 to 64 ̊API and separator 

pressures and temperatures ranging from 4 to 870 psig and 40 to 180 ̊F respectively. In 

total, the API study provided 103 E&P Tank runs; however, 2 were omitted as outliers. 

The U.S. Inventory divided these E&P Tank simulations into two ranges: 

• API gravities less than 45 ̊API were considered crude oil 

• API gravities greater than or equal to 45 ̊API were considered condensate 

It developed average emission factors of cubic feet of methane per barrel of hydrocarbon 

for both ranges, weighting the individual points by the associated production rates 
provided in the simulation inputs. The developed emission factors represent uncontrolled 

emissions due to hydrocarbon flashing in tanks and are displayed in Exhibit 5-1. 

The two most common control methods for these emissions are vapor recovery units 

(VRU’s) and flare systems. For oil tanks, the Inventory recognizes that regulations 

require controls on all tanks in Alaska, so Alaskan crude oil production is deducted from 

the activity factor, assuming there are no emissions from these tanks. 

The Inventory estimates that 50% of condensate storage tanks are equipped with emission 

controls. It adjusts the activity factor such that 50% of condensate is produced to tanks 

equipped with vapor recovery or connected to flare systems; and the other half of 

condensate is produced to tanks without controls. It assumes that for those tanks 

equipped with emissions control, 80% of the estimated emissions are captured by the 

control technologies. After emissions from condensate tanks are estimated, the inventory 

then calculates an incremental portion of those emissions that are affected by the 

NESHAP regulations, and deducts those from the total. These values are summarized in 

Exhibit 5-1. 

Exhibit 5-1. Inventory Results for Storage Tank Methane Emissions (2007) 

Crude Oil Condensate 

Total U.S. Production 1,848 MMbbl 123 MMbbl 

Throughput to Tanks with Controls 264 MMbbl (Alaska) 61.5 MMbbl 

Volume Not Produced to Tanks 259 MMbbl 

(80% of marginal well production) - 

Methane Emission Factor(s) 5.28 scf/bbl 21.87 scf/bbl (uncontrolled), 

4.37 scf/bbl (controlled) 

Incremental Reductions - 0.4 Bcf (NESHAP) 

Total Methane Emissions 7 Bcf 

(2.8 MMTCO2e) 

1.2 Bcf 

(0.5 MMTCO2e) 

The Inventory does not deduct emission reduction reported by Natural Gas STAR 

Partners like it does for most other sources because it assumes there will be doublecounting of reductions with the vapor recovery and regulation assumptions. For example, 

it assumes that the 50% of condensate tanks equipped with vapor recovery covers 

voluntary reductions from Natural Gas STAR and that the voluntary reductions prior to 

the enactment of the NESHAP regulations would overlap with those attributed to 

NESHAP in the analysis. 

Using the Inventory emission factors for uncontrolled tank emissions and applying them 

to the total national production for both crude oil and condensate production suggests a 

worst-case scenario in which approximately 12 Bcf (4.9 MMTCO2e) of methane could be 

emitted from tanks in the U.S. Natural Gas STAR Partners have reported voluntarily 

reducing over 18 Bcf (7.3 MMTCO2e) of methane emissions annually through 2007. 

That reduction does not include most activity from before 1998, the year in which the 

NESHAP regulation dictated additional vapor recovery, and it does not include activities 

from non-Partner companies in industry who also voluntarily install vapor recovery 

systems. If Natural Gas STAR reported emission reductions alone were deducted from 
the “worst-case scenario” presented above, U.S. emissions from storage tanks would be 

less than zero. 

►Methodology

This analysis revised the development of the uncontrolled emission factors using the 101 

samples of E&P Tank runs and revised assumptions pertaining to emission reductions 

from the Inventory. It also considered an additional phenomenon that contributes to tank 

venting beyond flashing emissions. The results of several measurement studies have 

been compared to flashing emissions predicted by software models based on 

thermodynamic equilibrium equations. In some cases the measured emissions were 

substantially more than the thermodynamic equilibrium software predicted. One Natural 

Gas STAR Partner shared an anecdotal experience that sometimes separator dump valves 

are set improperly or stick open which will empty all liquids plus high pressure gas from 

the separator directly to the stock tank. Another Gas STAR Partner shared data with the 

program wherein they measured the largest emission from compressor stations was gas 

blow-by through stuck-open dump valves on compressor scrubbers. This gas vented to 

the atmosphere from the condensate tank. 

The independent estimate estimated a range of tank emissions with just flashing as the 

base and flashing with blow-through as the high end. It accomplished this in the 

following steps: 

1. Estimate un-weighted flashing emission factors for hydrocarbon liquids 

2. Estimate tank throughputs for a significant sample of U.S. production 

3. Develop new weighted crude oil flashing emission factor based on significant 

sample of U.S. production 

4. Develop new weighted condensate flashing emission factor based on significant 

sample of U.S. production 

5. Estimate potential uncontrolled emissions from U.S. storage tanks 

6. Estimate regulated reductions from NESHAP and Alaska 

7. Estimate voluntary reductions from VRU’s 

8. Estimate potential effect of blow-through based on HARC and TCEQ studies. 

1. Estimate Un-weighted Flashing Emission Factors for Hydrocarbon Liquids

This analysis used the raw data available through the 101 E&P Tank sample runs to 

develop un-weighted average emission factors for hydrocarbon liquids within narrow API 

gravity ranges. It broke the sample runs into ranges of 5 ̊API, and then took the simple 

average of the flashing methane emission factor calculated from E&P Tank for all 

simulation runs in those ranges. The results of this are presented in Exhibit 5-2. 

Exhibit 5-2. Un-Weighted Flashing Methane Emission Factors by API Gravity 
API Gravity Range 

( ̊API) 

Flashing Methane 

Emission Factor 

(scf/bbl) 

Crude Oil 

0 to 19 2.10 

20 to 24 3.18 

25 to 29 2.67 

30 to 34 10.15 

35 to 39 6.80 

40 to 44 9.06 

Condensate 

45 to 49 6.62 

50 to 54 45.57 

55 to 59 106.73 

≥60 101.89 

In step (3) and step (4) these un-weighted emission factors are applied to a large sample 

of U.S. production data to develop new weighted EF’s for crude oil and condensate. 

2. Estimate Tank Throughputs for a Significant Sample of U.S. Production

This analysis used data available in the Lasser database on oil production from Texas, 

New Mexico, Mississippi, Louisiana, and parts of the Gulf of Mexico to determine a 

sample of tank throughputs. By production field, the database provides the annual oil 

production for 2007, the well type (marginal or non-marginal), and the hydrocarbon 

liquid API gravity. 

Using the Inventory assumption that all production from non-marginal wells and 20% of 

production from marginal wells pass through crude oil storage tanks, the amount of crude 

oil (hydrocarbons with API gravity less than 45 ̊API) produced to storage tanks was 

calculated for each field. 

Using the Inventory assumption that all condensate production passes through storage 

tanks, the amount of condensate (hydrocarbons with API gravity greater than or equal to 

45 ̊API) produced to storage tanks was calculated for each field. 

3. Develop New Weighted Crude Oil Flashing Emission Factor Based on Significant 

Sample of U.S. Production

The associated un-weighted flashing methane emission factors from step (1) were 

mapped to each field by matching the field’s average API gravity of produced 

hydrocarbon liquids with the API gravity ranges presented in Exhibit 5-2. The 

corresponding flashing methane emission factor from step (1) was multiplied by the 

crude oil storage tank throughput calculated in step (2) to estimate methane emissions 

from each oil production field in the database. The sum of these emissions was divided 

by the sum of all oil tank throughputs to develop a new flashing methane emission factor 

for crude oil weighted by a large sample of U.S. production data. This equation is 

displayed in Exhibit 5-3 below. 
Exhibit 5-3. Equation for Weighted Flashing Methane Emission Factor 

( )

∑

∑ ×

=

i

i

i

i i

oil

q

EF q

EF

Where, 

EFoil = weighted flashing methane emission factor for crude oil (scf/bbl) 

i = index representing field “i” 

EFi = un-weighted methane emission factor for crude oil corresponding to field “i” (scf/bbl) 

qi = throughput of tanks in field “i” (bbl) 

The resulting weighted emission factor was 7.06 scf/bbl. 

4. Develop New Weighted Condensate Flashing Emission Factor Based on Significant 

Sample of U.S. Production

Similar to step (3) for crude oil, the associated un-weighted flashing methane emission 

factors from step(1) were mapped to each field by matching the field’s average API 

gravity of produced hydrocarbon liquids with the API gravity ranges presented in Exhibit 

5-2. The corresponding flashing methane emission factor from step (1) was multiplied by 

the condensate storage tank throughput calculated in step (2) to estimate methane 

emissions from each gas and condensate production field in the database. The sum of 

these emissions was divided by the sum of all condensate tank throughputs to develop a 

new flashing methane emission factor for condensate weighted by a large sample of U.S. 

production data. This equation is displayed in Exhibit 5-4 below. 

Exhibit 5-4. Equation for Weighted Flashing Methane Emission Factor 

( )

∑

∑ ×

=

i

i

i

i i

condensate

q

EF q

EF

Where, 

EFcondensate = weighted flashing methane emission factor for condensate (scf/bbl) 

i = index representing field “i” 

EFi = un-weighted methane emission factor for crude oil corresponding to field “i” (scf/bbl) 

qi = throughput of tanks in field “i” (bbl) 

The resulting weighted emission factor was 71.02 scf/bbl. 

5. Estimate Potential Uncontrolled Emissions from U.S. Storage Tanks

The emissions from this sample set of data from Lasser were extrapolated to the U.S. by 

multiplying the weighted emission factors calculated in step (3) and step (4) to the 

corresponding oil tank throughput and condensate tank throughputs for the entire U.S. 

Crude oil tank throughput was estimated using EIA data for U.S. Crude Oil Production1

in 2007 by state, less the 80% of stripper well production calculated by the U.S. 

Inventory. This resulting crude oil tank throughput was 1,585 MMbbl in 2007. 
Condensate tank throughput was estimated by using EIA data for Lease Condensate 

Proved Reserves and Production2

 in 2007 by state. At this point in the analysis no 

controls were assumed to be on the tanks since regulatory and voluntary reductions are 

later calculated in step (6) and step (7). The resulting condensate throughput was 181 

MMbbl in 2007. 

Exhibit 5-5 summarizes the results as of this step in the analysis. 

Exhibit 5-5. Summary of Results before Accounting for Reductions (2007) 

Service Tank Throughput Emission Factor 

Emissions 

(uncontrolled) 

Crude Oil 1,585 MMbbl 7.06 scf/bbl 11 Bcf 

Condensate 181 MMbbl 71.02 scf/bbl 13 Bcf 

*NOTE: Voluntary and regulatory emission reductions have not been deducted from these totals. 

6. Estimate Regulated Reductions from NESHAP and Alaska

This analysis used the same methods as the U.S. Inventory to estimate emission 

reductions from the NESHAP regulation. The Inventory estimates and assumed the 

following: 

• Estimated 66.18% of all emissions were impacted by NESHAP 

• Estimated 88.89% of the throughput from those tanks is affected 

• Assumed that 10% of the affected throughput will have emission flared 

o Assumed flares have 98% combustion efficiency 

• Assumed 90% of affected throughput will have vapor recovery 

o Assumed that vapor recovery recovers 95% of emissions 

It combined those estimates and assumptions into the equation in Exhibit 5-6: 

Exhibit 5-6. NESHAP Emission Reductions from Condensate Tanks (2007) 

R = 7Bcf =13Bcf × 66.18%×88.89%×[(10%× (1− 98%)) () + ( ) 90%× 1− 95% ] NESHAP

Thus, this analysis estimates that 7 Bcf of emissions from condensate tanks were reduced 

in 2007 due to the NESHAP regulation. 

In addition to the NESHAP regulation for condensate tanks, Alaska has permitting 

regulations that require all crude oil storage tanks have emissions control. The total 

crude oil production in Alaska for 2007 was 527 MMbbl. If emissions from this 

production were mitigated, then 527 MMbbl multiplied by the crude oil uncontrolled 

emission factor, 7.06 scf/bbl, equals approximately 2 Bcf of emission reductions from 

crude oil tanks. 

7. Estimate Voluntary Reductions from VRU’s

Voluntary emission reduction by installing VRU’s on storage tanks were estimated using 

iSTAR summary reports on Natural Gas STAR Partner reported activities. For internal 

purposes, Natural Gas STAR implements a “sunsetting” policy. When an emissions 

reduction technology continually reduces emission, like a VRU, Natural Gas STAR only 
gives credit for ten years to account for the normal cycle of technology improvement. 

For example, the data in the iSTAR reductions report for VRU’s stops crediting annual 

reductions after 10 years. In reality, these VRU’s are still functioning and continuing to 

reduce emissions from storage tanks. This analysis removed the sunsetting effect from 

the iSTAR report. 

When the NESHAP regulations were imminent, it is believed that many companies 

implemented vapor recovery systems before the regulation began in preparation for it. At 

the initiation of the project, the reductions were voluntary, but after NESHAP went into 

effect in 1998, those emissions were no longer voluntary. Thus, it was assumed that the 

emissions reductions from condensate storage tanks due to NESHAP in 1998 would 

overlap with reported voluntary VRU projects prior to 1998. This analysis subtracted the 

1998 NESHAP tank emission reductions from the un-sunsetted reduction data from 

Natural Gas STAR prior to 1998. The remaining emissions reductions are from projects 

implemented before 1998 which were still voluntary in 2007. 

Finally, this analysis removed sunsetting from the voluntary emission reductions after the 

start of NESHAP in 1998 to account for voluntary emission reductions from project that 

initiated after NESHAP (assuming they were applied to tanks not subject to the 

NESHAP). 

The total voluntary emission reductions in 2007 are then the sum of voluntary reductions 

from projects that started after 1998 and currently voluntary reductions from projects that 

started before 1998. These results are presented in Exhibit 5-7. 

Exhibit 5-7. Voluntary Reductions of Storage Tank Emissions (2007) 

Category Annual Emissions Reductions 

VRU additions after NESHAP (sunsetting 

removed)* 14 Bcf 

VRU projects before NESHAP (sunsetting 

removed)* + 6 Bcf 

NESHAP initial year reductions** - 2 Bcf 

Total annual voluntary reductions (2007) 18 Bcf 

* Source: iSTAR 

**Source: U.S. Inventory 

8. Estimate Potential Effect of Blow-through

Steps (1) through (6) only estimate emissions due to flashing from hydrocarbon liquids; 

however, there is evidence that suggests in many cases high pressure gas from the 

separator either vortexes through the liquid drain and into the tank or the dump valves 

allow the liquids to empty entirely and gas blows directly through to the tank. This 

analysis considered data from two measurement studies, one conducted by Houston 

Advanced Research Center (HARC)3

 and another by Texas Commission on 

Environmental Quality (TCEQ)4

. 

The studies measured tank emissions from a combined 69 crude oil and condensate 

storage tank batteries. The TCEQ study also compared its measured results to those 

obtained from other quantification methods – such E&P Tank. The HARC study did not 
provide E&P Tank simulation results, so this study performed a back-of-the-envelop 

calculation to make a comparison. It used the Vasquez-Beggs Equation on the data 

provided for the 36 batteries in TCEQ and determined the average ratio of E&P Tank 

results to Vasquez-Beggs results for the gas-oil ratio (GOR) of the flash emissions. It 

then performed the same Vasquez-Beggs correlation to 32 of the 33 tank batteries in 

HARC and used the ratio to back-calculate an estimate of E&P Tank results. This 

analysis excluded one of the 33 data points because the HARC study states that a well 

was completed with the gas routed through the tank battery during measurement; thus, 

highly skewing the results. 

The average ratio of measured emissions to the E&P Tank simulated (or estimated) 

emissions was calculated separately for crude oil and condensate tanks. In some tank 

batteries, the simulation of flashing emissions corresponded reasonably well (within 

100%) with the measured emissions. However, in 30 of the 68 accepted cases, or 44% of 

the cases, the measured emissions were much different; typically higher. 

Since the proportion of tanks which experience some sort of blow-through or vortexing 

was not known and had not been studied, it was assumed that up to 44% of tanks in the 

U.S. also experience these incremental emissions in addition to flashing. Thus, the 

average ratio of measured emissions to simulated flashing emissions for the entire 

population of 68 tank batteries was calculated for crude oil and condensate, then applied 

to the flashing emission estimates to provide an upper-bound of emissions. The resulting 

ratios of measured emissions to E&P Tank estimated flashing emissions was 2.17 for 

crude oil and 4.26 for condensate. This upper-bound was calculated using the equation in 

Exhibit 5-8. 

Exhibit 5-8. Equation to Estimate Incremental Non-Flashing Emissions 

Eupper = (E flash × R)− ER

Where, 

Eupper = tank emissions upper-bound, includes flashing emissions and vortexing or blow-through 

Eflash = uncontrolled emissions from flashing (Exhibit 5-5) 

R = average ratio of measured emissions to flashing emissions, 2.17 for oil and 4.26 for condensate 

ER = emission reductions from NESHAP, Alaska, and voluntary reductions (Exhibits 5-6, 5-7, and 

step (6)) 

Using the equation in Exhibit 5-8, the total upper-bound emissions from storage tanks in 

the U.S. was estimated to be 26 Bcf. 

►Results

The results of the analysis outlined in the steps above are compared along side the results 

of the U.S. Inventory in Exhibit 5-9. 
Exhibit 5-9. Comparison of U.S. Inventory to Revised Analysis (2007) 

U.S. Inventory 

Revised Analysis: 

Flashing Only 

Revised Analysis: 

Upper-bound 

Uncontrolled Methane Emissions 12 Bcf 24 Bcf 75 Bcf 

Regulatory Reductions 9 Bcf 35 Bcf 

Voluntary Reductions (Gas STAR) 4 Bcf 18 Bcf 14 Bcf 

Total Estimated Methane Emissions 8 Bcf N/A 26 Bcf 

(11 MMTCO2e) 

Note that the regulatory and voluntary reductions changed with method. In the case of 

the U.S. Inventory, the key assumption is that deducting Natural Gas STAR reported 

voluntary reductions would be double-counting; and thus, a very large portion of actual 

reported emission reductions are not considered. If these reductions were included, the 

inventory would yield negative total emissions. 

In the case of the revised analysis for flashing emissions only, the conclusion is that 

flashing emissions alone do not fully describe emissions from tanks. Regulatory 

reductions are scaled from the total estimated uncontrolled emissions from Alaskan crude 

and a proportion of emissions from condensate tanks mitigated by NESHAP. Since these 

are scaled from the uncontrolled emission estimates; as those increase, so do the 

estimated regulatory reductions. 

The revised analysis upper-bound captures incremental emissions beyond gas flashing 

out of a liquid hydrocarbon solution. It represents a case where high pressure gas from 

the separator is bypassing the separator dump valve and being vented from the storage 

tank. As these uncontrolled emissions estimates greatly increase, so do the regulatory 

reductions because those emissions must be captured or flared. Voluntary reduction from 

Natural Gas STAR; however, are less than the revised analysis’ estimates. This is 

unintuitive, but the emission reductions due to the first year of NESHAP increase to 

much larger than the annual reductions from Natural Gas STAR prior to NESHAP’s 

enactment. It is assumed that all such reductions stopped being voluntary once NESHAP 

came into effect and are captured under regulatory reductions. 

 

1

 EIA. U.S. Crude Oil Production. Annual data for 2007. Available online at 

<http://tonto.eia.doe.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm>. Revised data as of June 29, 2009. 2

 EIA. Lease Condensate Proved Reserves and Production. Annual data for 2007. Available online at: 

<http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/histori

cal/2007/cr2007.html>. Revised data as of February 10, 2009. 

3

 HARC. VOC Emissions from Oil and Condensate Storage Tanks. October 31, 2006. 4

 TCEQ. Upstream Oil and Gas Storage Tank Project Flash Emissions Model Evaluation. July 16, 2009.