Canadian dollars.
The remainder of the increase in North America Onshore LOE is primarily due to increased costs related to our Jackfish operation in Canada.
U. S.  Offshore LOE decreased primarily due to property divestitures in the second quarter of 2010.
The increase due to exchange rates was also the main contributor to the changes in North America Onshore and total LOE per Boe.2009 vs.  2008 LOE decreased $181 million in 2009.
LOE dropped $182 million due to declining costs for fuel, materials, equipment and personnel, as well as declines in maintenance and well workover projects.
Such declines largely resulted from decreasing demand for field services due to lower oil and gas prices.
Changes in the exchange rate between the U. S.  and Canadian dollar reduced LOE $49 million.
Additionally, LOE decreased $31 million as a result of hurricane damages in 2008 to certain of our U. S.  Offshore facilities and transportation systems.
These factors, excluding the hurricane damage, were also the main contributors to the decrease in LOE per Boe on our North America Onshore properties.
Production growth at our large-scale Jackfish project also contributed to a decrease in LOE per Boe.
As Jackfish production approached the facility’s capacity during 2009, its per-unit costs declined, contributing to lower overall LOE per Boe.
The remainder of our four percent company-wide production growth added $81 million to LOE during 2009.
Taxes Other Than Income Taxes Taxes other than income taxes consist primarily of production taxes and ad valorem taxes assessed by various government agencies on our U. S.  Onshore properties.
Production taxes are based on a percentage of production revenues that varies by property and government jurisdiction.
Ad valorem taxes generally are based on property values as determined by the government agency assessing the tax.
The following table details the changes in our taxes other than income taxes.
## Table 0 ##
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.2010 vs.  2009 Production taxes increased $78 million in 2010.
This increase was largely due to higher U. S.  Onshore revenues, as well as a decrease in production tax credits associated with certain properties in the state of Texas.
Ad valorem taxes decreased $10 million primarily due to lower assessed values of our U. S.  Onshore oil and gas property and equipment.2009 vs.  2008 Production taxes decreased $174 million in 2009.
This decrease was largely due to lower U. S.  Onshore revenues, as well as an increase in production tax credits associated with certain properties in the state of Texas.
Ad valorem taxes increased $13 million primarily due to higher assessed oil and gas property and equipment values.
Depreciation, Depletion and Amortization of Oil and Gas Properties (“DD&A”) DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced during the year, by the “depletable base.
” The depletable base represents our capitalized investment, net of accumulated DD&A and reductions of carrying value, plus future development costs related to proved undeveloped reserves.
Generally, when reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely.
However, when the depletable base changes, then the DD&A rate moves in the same direction.
The per unit DD&A rate is not affected by production volumes.
Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes.
Oil and gas property DD&A is calculated separately on a country-by-country basis.
## Table 1 ##
(1) Prices presented exclude any effects due to oil, gas and NGL derivatives.
Commodity Sales The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales.
## Table 2 ##
Volumes 2012 vs.  2011 – Upstream sales increased $695 million due to a 4 percent increase in production.
Oil and bitumen production were the largest drivers of the increase, accounting for nearly 90 percent of the higher sales.
As a result of continued development of our liquids-rich properties in the Permian Basin, our oil sales increased $337 million.
Bitumen sales increased $273 million due to development of our Jackfish thermal heavy oil projects in Canada.
Additionally, our NGL sales increased $137 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale, Cana-Woodford Shale and Granite Wash.
These increases were partially offset by a slight decrease in our 2012 gas production, resulting in a $52 million decline in sales.
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) Debt maturities as of December 31, 2012, excluding premiums and discounts, are as follows (in millions):
## Table 3 ##
Credit Lines Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”).
The Senior Credit Facility has an initial maturity date of October 24, 2017.
However, prior to the maturity date, Devon has the option to extend the maturity for up to two additional one-year periods, subject to the approval of the lenders.
Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months.
Such rates are generally less than the prime rate.
However, Devon may elect to borrow at the prime rate.
The Senior Credit Facility currently provides for an annual facility fee of $3.8 million that is payable quarterly in arrears.
As of December 31, 2012, there were no borrowings under the Senior Credit Facility.
The Senior Credit Facility contains only one material financial covenant.
This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent.
The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying financial statements.
Also, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwill impairments.
As of December 31, 2012, Devon was in compliance with this covenant with a debt-tocapitalization ratio of 25.4 percent.
Commercial Paper Devon has access to $5.0 billion of short-term credit under its commercial paper program.
Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing.
The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market.
As of December 31, 2012, Devon’s weighted average borrowing rate on its commercial paper borrowings was 0.37 percent.
Other Debentures and Notes Following are descriptions of the various other debentures and notes outstanding at December 31, 2012, as listed in the table presented at the beginning of this note.
borrowings outstanding at the end of 2018 and 2017 represent borrowings made under, or supported by, these lines of credit.
Borrowings under the lines of credit were made by certain international affiliates of the Company on terms and at interest rates generally extended to companies of comparable creditworthiness in those markets.
The weighted average interest rates of the outstanding borrowings under the uncommitted lines of credit as of December 30, 2018 and December 31, 2017 were 3.92% and 4.32%, respectively.
The Company had no borrowings outstanding under its committed line of credit at December 30, 2018.
During 2018, Hasbro’s working capital needs were fulfilled by cash available and cash generated from operations.
During the fourth quarter of 2018, the Company entered into an amended and restated revolving credit agreement with the lenders party thereto (the “Amended Agreement”) which provides the Company with a $1,100,000 committed borrowing facility.
The Amended Agreement contains certain financial covenants setting forth leverage and coverage requirements, and certain other limitations typical of an investment grade facility, including with respect to liens, mergers and incurrence of indebtedness.
The Amended Agreement also provides for a potential additional incremental commitment increase of up to $500,000.
The Amended Agreement extends the term of our prior facility from March 30, 2020 to November 26, 2023.
The Amended Agreement contains certain financial covenants setting forth leverage and coverage requirements, and certain other limitations typical of an investment grade facility, including with respect to liens, mergers and incurrence of indebtedness.
The Company was in compliance with all covenants as of and for the fiscal year ended December 30, 2018.
The Company pays a commitment fee (0.10% as of December 30, 2018) based on the unused portion of the facility and interest equal to a Base Rate or Eurocurrency Rate plus a spread on borrowings under the facility.
The Base Rate is determined based on either the Federal Funds Rate plus a spread, Prime Rate or Eurocurrency Rate plus a spread.
The commitment fee and the amount of the spread to the Base Rate or Eurocurrency Rate both vary based on the Company’s long-term debt ratings and the Company’s leverage.
At December 30, 2018, the interest rate under the facility was equal to Eurocurrency Rate plus 1.125%.
The Company has an agreement with a group of banks providing a commercial paper program (the “Program”).
Under the Program, at the Company’s request the banks may either purchase from the Company, or arrange for the sale by the Company of, unsecured commercial paper notes.
Borrowings under the Program are supported by the aforementioned unsecured committed line of credit and the Company may issue notes from time to time up to an aggregate principal amount outstanding at any given time of $1,000,000.
The maturities of the notes may vary but may not exceed 397 days.
Subject to market conditions, the notes will be sold under customary terms in the commercial paper market and will be issued at a discount to par, or alternatively, will be sold at par and will bear varying interest rates based on a fixed or floating rate basis.
The interest rates will vary based on market conditions and the ratings assigned to the notes by the credit rating agencies at the time of issuance.
At December 30, 2018, the Company did not have any notes outstanding under the Program.
At December 31, 2017, the Company had notes outstanding under the Program of $137,500 with a weighted average interest rate of 1.85%.
(9) Accrued Liabilities Components of accrued liabilities for the fiscal years ended on December 30, 2018 and December 31, 2017 are as follows:

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Year Ended December 31,
2010	2010 vs 2009-1	2009	2009 vs 2008-1	2008
($ in millions)
Production	$210	+59%	$132	−57%	$306
Ad valorem	165	−6%	175	+8%	162
Other	5	−30%	7	−4%	8
Total	$380	+21%	$314	−34%	$476

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Year Ended December 31,
2012-1	Change	2011-1	Change	2010-1
Oil (per Bbl)
U.S. Onshore	$88.68	-3%	$91.19	+21%	$75.53
Canada	$68.08	-8%	$74.32	+20%	$62.00
North America Onshore	$80.35	-3%	$83.16	+22%	$68.17
U.S. Offshore	$—	N/M	$—	-100%	$77.81
Total	$80.35	-3%	$83.16	+21%	$68.75
Bitumen (per Bbl)
Canada	$47.75	-18%	$58.16	+11%	$52.51
Gas (per Mcf)
U.S. Onshore	$2.32	-34%	$3.50	-6%	$3.73
Canada	$2.49	-36%	$3.87	-6%	$4.11
North America Onshore	$2.36	-34%	$3.58	-6%	$3.82
U.S. Offshore	$—	N/M	$—	-100%	$5.12
Total	$2.36	-34%	$3.58	-7%	$3.84
NGLs (per Bbl)
U.S. Onshore	$28.49	-28%	$39.47	+28%	$30.78
Canada	$48.63	-13%	$55.99	+20%	$46.60
North America Onshore	$30.42	-26%	$41.10	+26%	$32.55
U.S. Offshore	$—	N/M	$—	-100%	$38.22
Total	$30.42	-26%	$41.10	+26%	$32.61
Combined (per Boe)
U.S. Onshore	$25.59	-18%	$31.31	+10%	$28.42
Canada	$37.01	-14%	$43.23	+11%	$39.11
North America Onshore	$28.65	-17%	$34.64	+10%	$31.52
U.S. Offshore	$—	N/M	$—	-100%	$49.06
Total	$28.65	-17%	$34.64	+9%	$31.91

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Oil	Bitumen	Gas	NGLs	Total
(In millions)
2010 sales	$2,169	$474	$3,572	$1,047	$7,262
Change due to volumes	30	193	88	147	458
Change due to prices	461	72	-249	311	595
2011 sales	2,660	739	3,411	1,505	8,315
Change due to volumes	337	273	-52	137	695
Change due to prices	-101	-181	-1,148	-427	-1,857
2012 sales	$2,896	$831	$2,211	$1,215	$7,153

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2013	$3,189
2014	500
2015	—
2016	500
2017	750
2018 and thereafter	6,725
Total	$11,664

']

Question: In the year with largest value of sales of oil, what's the sum of sales of gas? (in million)
Answer: 2211