·	Delivers 35 Percent Year-Over-Year Total Company Crude Oil Production Growth

·	Raises 2013 Full Year Crude Oil Production Target to 35 Percent from 28 Percent

·	Increases Total Company Overall Production Growth Target to 7.5 Percent from 4 Percent

·	Announces Record South Texas Eagle Ford Oil Well

·	Extends Bakken/Three Forks Drilling Inventory and Posts Excellent North Dakota Well Results

·	Drives Down Costs in Key Areas of Operations

FOR IMMEDIATE RELEASE: Tuesday, August 6, 2013

HOUSTON – EOG Resources, Inc. (EOG) today reported second quarter 2013 net income of $659.7 million, or $2.42 per share. This compares to second quarter 2012 net income of $395.8 million, or $1.47 per share.

Consistent with some analysts' practice of matching realizations to settlement months and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the second quarter 2013 was $573.8 million, or $2.10 per share. Adjusted non-GAAP net income for the second quarter 2012 was $312.4 million, or $1.16 per share. The results for the second quarter 2013 included net gains on asset dispositions of $9.4 million, net of tax ($0.04 per share), impairments of $2.0 million, net of tax ($0.01 per share) related to the sale of certain non-core North American assets and a previously disclosed non-cash net gain of $191.5 million ($122.6 million after tax, or $0.45 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $68.9 million ($44.1 million after tax, or $0.16 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

EOG reported strong, sustained financial growth for the second quarter 2013. Compared to the second quarter 2012, earnings per share increased 65 percent, discretionary cash flow increased 35 percent and adjusted EBITDAX rose 34 percent. (Please refer to the attached tables for the reconciliation of non-GAAP discretionary cash flow to net cash provided by operating activities (GAAP) and adjusted EBITDAX (non-GAAP) to income before interest expense and income taxes (GAAP).)

"EOG has captured premier positions in key U.S. onshore oil plays – the South Texas Eagle Ford, North Dakota Bakken and Delaware Basin, and we continue to enhance their profitability," said Mark G. Papa, Executive Chairman of the Board. "EOG's financial metrics reflect the superior quality of these assets, as well as our technical acumen in improving well completion design and our ongoing focus on reducing costs."

EOG's U.S. crude oil and condensate production increased 37 percent both in the second quarter and the first half of 2013, compared to the same periods in 2012. Total company crude oil and condensate production increased 35 percent in the second quarter over the same prior year period. Total company liquids – crude oil, condensate and natural gas liquids (NGLs) – production rose 30 percent, versus the second quarter 2012.

Based on its exceptional performance during the first half of 2013, EOG is increasing its full year crude oil and condensate production growth target to 35 percent from 28 percent. Total NGL production is expected to increase 14 percent from the previous 10 percent target, while natural gas production is projected to decline 11.5 percent during 2013. Overall, EOG is targeting 7.5 percent total company production growth in 2013. EOG also anticipates certain unit costs will be lower than originally forecast.

 "We have the confidence to raise the bar on EOG's performance expectations because our outstanding assets perform better and better, quarter after quarter," said President and Chief Executive Officer William R. "Bill" Thomas. "EOG expects to achieve these higher goals within our previously stated capex estimate."

At June 30, 2013, EOG's Eagle Ford net production of approximately 173,000 barrels of oil equivalent per day, continued to out-perform the rest of the industry.

Since discovering the prolific Eagle Ford, EOG has more than doubled the initial crude oil production rates from its wells in both the western and eastern parts of the play. Efficiency gains from more effective completions and reduced drilling days are resulting in excellent rates of return.

EOG recorded strong well and economic results from its western Eagle Ford acreage where more than a third of its second quarter drilling activity in the play occurred. In La Salle County, EOG's initial production rates and overall well productivity showed a marked improvement, compared to similar completions in the same area three years ago. The Keller #1H and #2H began production at rates of 1,855 and 2,050 barrels of crude oil per day (Bopd) with 75 and 50 barrels per day (Bpd) of NGLs and 430 and 300 thousand cubic feet per day (Mcfd) of natural gas, respectively. The Smart Unit #1H and #2H had initial rates of 1,495 and 2,030 Bopd with 60 and 75 Bpd of NGLs and 340 and 440 Mcfd of natural gas, respectively. The Dossett Unit #1H and #2H were completed to sales at 1,590 and 2,185 Bopd with 85 and 115 Bpd of NGLs and 490 and 655 Mcfd of natural gas, respectively. In McMullen County, the Naylor Jones B #1H started production at 1,830 Bopd with 240 Bpd of NGLs and 1.4 million cubic feet per day (MMcfd) of natural gas. EOG has 100 percent working interest in these seven wells.

EOG again achieved excellent well results in Gonzales County, the northeastern area of its Eagle Ford acreage. The Burrow Unit #3H, #4H and #5H were completed to sales in May at initial production rates of 2,990, 3,030 and 7,515 Bopd with 385, 370 and 860 Bpd of NGLs and 2.2, 2.1 and 5.0 MMcfd of natural gas, respectively. After 30 days, the Burrow Unit #5H, EOG's best Eagle Ford well to date, had an average production rate of 4,265 Bopd. The Wilde Trust Unit #1H, #2H and #3H began production in early June at rates of 5,475, 6,520 and 5,525 Bopd with 880, 710 and 775 Bpd of NGLs and 5.1, 4.1 and 4.5 MMcfd of natural gas, respectively. EOG has 100 percent working interest in these six Gonzales County wells.

"With wells in our western drilling program following the same trend as those in the east, results from the EOG's Eagle Ford activity continue to outpace our expectations," Papa said.

Improved drilling efficiencies and completion technology also have enhanced well productivity in EOG's Bakken/Three Forks operations. During the second quarter, EOG's North Dakota drilling program focused on the Bakken formation. In the Bakken Core, results from 160-acre spacing between wells continue to be encouraging. In Mountrail County, two Core wells drilled on 160-acre spacing, the Parshall 25-3032H and 22-3032H, were completed to sales at 2,685 and 2,120 Bopd, respectively. EOG has 62 percent working interest in these wells. EOG has 78 percent working interest in the Van Hook 29-1113H and 30-1113H, which began production at 2,390 and 2,295 Bopd, respectively, which were also 160-acre spaced wells.

In the Antelope Extension, EOG's other North Dakota development target this year, the Bear Den 20-1708H was completed in the Bakken formation at 2,455 Bopd. EOG has 91 percent working interest in the well.

Based on the success of its current spacing programs, EOG has increased its drilling inventory in the Bakken/Three Forks from seven to 12 years.

EOG remains active in the Delaware Basin Leonard and Wolfcamp, although the plays are constrained by a lack of natural gas processing infrastructure that is being addressed. In Reeves County, Texas, EOG drilled its best Delaware Basin Wolfcamp well to date. EOG has 100 percent working interest in the Phillips State 56 #301H, which was completed to sales at 870 Bopd with 570 Bpd of NGLs and 3.7 MMcfd of natural gas.

EOG completed and brought to sales a number of highly economic wells in the Leonard formation in Lea County, New Mexico. The Diamond 31 Fed Com #2H, #3H and #4H came online at 1,780, 1,905 and 1,530 Bopd with 215, 165 and 150 Bpd of NGLs and 1,200, 910 and 835 Mcfd of natural gas, respectively. EOG has 91 percent working interest in these wells.

"We expect EOG's three high rate-of-return oil plays, the Eagle Ford, Bakken/Three Forks and Delaware Basin, to provide us with years of drilling inventory, as well as significant growth opportunities," Papa said. "These plays just get bigger and better."

In recent weeks, EOG has increased the amount of crude oil hedges in place for the remainder of 2013. For the period August 1 through December 31, 2013, EOG has crude oil financial price swap contracts in place for approximately 121,200 Bpd at a weighted average price of $98.82 per barrel, excluding unexercised options.

For the full year 2014, EOG has crude oil financial price swap contracts in place for approximately 51,000 Bpd at a weighted average price of $96.43 per barrel, excluding unexercised options.

EOG also has hedged some natural gas volumes for 2013 and 2014. For the period September 1 through October 31, 2013, EOG has natural gas financial price swap contracts in place for 200,000 million British thermal units per day (MMBtud) at a weighted average price of $4.72 per million British thermal units (MMBtu), excluding unexercised options. For the period November 1 through December 31, 2013, EOG has hedged 150,000 MMBtud at a weighted average price of $4.79 per MMBtu, excluding unexercised options. For the full year 2014, EOG has natural gas financial price swap contracts in place for 170,000 MMBtud at a weighted average price of $4.54 per MMBtu, excluding unexercised options. (For a comprehensive summary of crude oil and natural gas derivative contracts, please refer to the attached tables.)

To date, EOG has closed on approximately $580 million of asset sales, exceeding its stated goal for the year. At June 30, 2013, EOG's total debt outstanding was $6,313 million for a debt-to-total capitalization ratio of 31 percent. Taking into account cash on the balance sheet of $1,228 million at the end of the second quarter, EOG's net debt was $5,085 million for a net debt-to-total capitalization ratio of 26 percent. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

EOG's second quarter 2013 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, August 7, 2013. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through August 21, 2013.

 

This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements.  EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements.  In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate income or cash flows or pay dividends are forward-looking statements.  Forward-looking statements are not guarantees of performance.  Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.  Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control.  Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

·	the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;

·	the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

·	the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;

·

the extent to which EOG is successful in its efforts to economically develop its acreage in, and to produce reserves and achieve anticipated production levels from, its existing and future crude oil and natural gas exploration and development projects, given the risks and uncertainties and capital expenditure requirements inherent in drilling, completing and operating crude oil and natural gas wells and the potential for interruptions of development and production, whether involuntary or intentional as a result of market or other conditions;

·	the extent to which EOG is successful in its efforts to market its crude oil, natural gas and related commodity production;

·	the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

·	the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses and leases;

·

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

·	EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

·	the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully and economically;

·	competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

·	the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;

·	weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation of production, gathering, processing, compression and transportation facilities;

·	the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;

·	EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;

·	the extent and effect of any hedging activities engaged in by EOG;

·	the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;

·	political conditions and developments around the world (such as political instability and armed conflict), including in the areas in which EOG operates;

·	the use of competing energy sources and the development of alternative energy sources;

·	the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;

·	acts of war and terrorism and responses to these acts;

·	physical, electronic and cyber security breaches; and

·	the other factors described under Item 1A, "Risk Factors", on pages 16 through 23 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2012 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves).  As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines.  Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.  In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.

 

EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
(Unaudited)
		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2013				2012				2013				2012
Wellhead Volumes and Prices
Crude Oil and Condensate Volumes (MBbld) (A)
United States			206.5				150.5				192.4				140.7
Canada			6.4				6.4				7.1				7.0
Trinidad			1.4				1.7				1.3				1.9
Other International (B)			0.1				0.1				0.1				0.1
Total			214.4				158.7				200.9				149.7
Average Crude Oil and Condensate Prices ($/Bbl) (C)
United States		$	103.73			$	95.80			$	105.04			$	98.61
Canada			89.66				82.78				87.29				86.33
Trinidad			86.96				88.68				90.36				94.76
Other International (B)			92.28				91.20				93.56				96.49
Composite			103.19				95.20				104.31				98.00
Natural Gas Liquids Volumes (MBbld) (A)
United States			63.7				54.6				61.2				52.4
Canada			1.0				0.9				0.9				0.9
Total			64.7				55.5				62.1				53.3
Average Natural Gas Liquids Prices ($/Bbl) (C)
United States		$	30.19			$	33.54			$	30.87			$	38.12
Canada			39.49				42.89				40.62				46.54
Composite			30.33				33.72				31.02				38.27
Natural Gas Volumes (MMcfd) (A)
United States			928				1,070				931				1,067
Canada			79				96				79				100
Trinidad			346				422				349				396
Other International (B)			8				10				8				10
Total			1,361				1,598				1,367				1,573
Average Natural Gas Prices ($/Mcf) (C)
United States		$	3.73			$	2.09			$	3.41			$	2.28
Canada			3.17				2.21				3.21				2.33
Trinidad			3.82				3.42				3.86				3.21
Other International (B)			6.81				5.64				6.78				5.72
Composite			3.73				2.47				3.53				2.54
Crude Oil Equivalent Volumes (MBoed) (D)
United States			424.8				383.3				408.8				370.9
Canada			20.6				23.4				21.2				24.6
Trinidad			59.0				72.0				59.4				67.9
Other International (B)			1.5				1.8				1.4				1.8
Total			505.9				480.5				490.8				465.2
Total MMBoe (D)			46.0				43.7				88.8				84.7

(A)	Thousand barrels per day or million cubic feet per day, as applicable.
(B)	Other International includes EOG's United Kingdom, China and Argentina operations.
(C)	Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments.
(D)	Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalents are determined using the ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.

 

EOG RESOURCES, INC.

QUANTITATIVE RECONCILIATION OF ADJUSTED EARNINGS BEFORE INTEREST EXPENSE,

INCOME TAXES, DEPRECIATION, DEPLETION AND AMORTIZATION, EXPLORATION COSTS,

DRY HOLE COSTS, IMPAIRMENTS AND ADDITIONAL ITEMS (ADJUSTED EBITDAX)

(NON-GAAP) TO INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES (GAAP)

(Unaudited; in thousands)

The following chart adjusts the three-month and six-month periods ended June 30, 2013 and 2012 reported Income Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash realized from financial commodity derivative transactions by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net gains on asset dispositions primarily in North America in 2013 and 2012.  EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items.  EOG management uses this information for comparative purposes within the industry.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2013				2012				2013					2012
Income Before Interest Expense and Income Taxes (GAAP)		$	1,096,877			$	697,014			$	1,919,817				$	1,267,417
Adjustments:
Depreciation, Depletion and Amortization			910,531				808,765				1,756,919					1,557,508
Exploration Costs			47,323				48,149				91,539					90,956
Dry Hole Costs			35,750				11,081				39,712					11,081
Impairments			37,967				54,217				91,515					187,364
EBITDAX (Non-GAAP)			2,128,448				1,619,226				3,899,502					3,114,326
Total Gains on MTM Commodity Derivative Contracts			(191,490	)			(188,449	)			(86,534	)				(322,657	)
Realized Gains on MTM Commodity Derivative Contracts			68,909				173,179				135,959					306,780
Net Gains on Asset Dispositions			(13,153	)			(113,290	)			(177,386	)				(180,758	)
Adjusted EBITDAX (Non-GAAP)		$	1,992,714	(a)		$	1,490,666	(b)		$	3,771,541				$	2,917,691
Percentage Increase - [(a) - (b)] / (b)			34	%

CRUDE OIL DERIVATIVE CONTRACTS
					Weighted
			Volume		Average Price
			(Bbld)		($/Bbl)
	2013 (1)
	January 2013 (closed)		101,000		$99.29
	February 1, 2013 through April 30, 2013 (closed)		109,000		99.17
	May 1, 2013 through June 30, 2013 (closed)		101,000		99.29
	July 2013 (closed)		111,000		98.25
	August 1, 2013 through September 30, 2013		126,000		98.80
	October 1, 2013 through December 31, 2013		118,000		98.84
	2014 (2)
	January 1, 2014 through March 31, 2014		103,000		$96.48
	April 1, 2014 through June 30, 2014		93,000		96.47
	July 1, 2014 through December 31, 2014		5,000		95.43

(1)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional three-month and six-month periods.  Options covering a notional volume of 8,000 Bbld are exercisable on September 30, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 8,000 Bbld at an average price of $98.11 per barrel for each month during the period October 1, 2013 through December 31, 2013.  Options covering a notional volume of 64,000 Bbld are exercisable on December 31, 2013.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 64,000 Bbld at an average price of $99.58 per barrel for each month during the period January 1, 2014 through June 30, 2014.

(2)

EOG has entered into crude oil derivative contracts which give counterparties the option to extend certain current derivative contracts for additional six-month and nine-month periods.  Options covering a notional volume of 10,000 Bbld are exercisable on or about March 31, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 10,000 Bbld at an average price of $96.60 per barrel for each month during the period April 1, 2014 through December 31, 2014.  Options covering a notional volume of 93,000 Bbld are exercisable on or about June 30, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 93,000 Bbld at an average price of $96.47 per barrel for each month during the period July 1, 2014 through December 31, 2014.  Options covering a notional volume of 5,000 Bbld are exercisable on December 31, 2014.  If the counterparties exercise all such options, the notional volume of EOG's existing crude oil derivative contracts will increase by 5,000 Bbld at an average price of $95.43 per barrel for each month during the period January 1, 2015 through June 30,2015.

(3)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Such options are exercisable monthly up until the settlement date of each monthly contract.  For the period September 1, 2013 through October 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 200,000 MMBtud at an average price of $4.72 per MMBtu for each month during that period.  For the period November 1, 2013 through December 31, 2013, if the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 150,000 MMBtud at an average price of $4.79 per MMBtu for each month during that period.

(4)

EOG has entered into natural gas derivative contracts which give counterparties the option of entering into derivative contracts at future dates.  Additionally, in connection with certain natural gas derivative contracts settled in July 2012, counterparties retain an option of entering into derivative contracts at future dates.  All such options are exercisable monthly up until the settlement date of each monthly contract.  If the counterparties exercise all such options, the notional volume of EOG's existing natural gas derivative contracts will increase by 320,000 MMBtud at an average price of $4.66 per MMBtu for each month during the period January 1, 2014 through December 31, 2014.

Bbld	Barrels per day
$/Bbl	Dollars per barrel
MMBtud	Million British thermal units per day
$/MMBtu	Dollars per million British thermal units
MMBtu	Million British thermal units