Marathon Oil Reports First Quarter 2019 Results

Prioritizing Return of Capital to Shareholders through Sustainable Free Cash Flow Generation

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May 01, 2019, 16:30 ET

HOUSTON, May 1, 2019 /PRNewswire/ -- Marathon Oil Corporation (NYSE: MRO) today reported first quarter 2019 net income of $174 million, or $0.21 per diluted share, which includes the impact of certain items not typically represented in analysts' earnings estimates and that would otherwise affect comparability of results. Adjusted net income was $256 million, or $0.31 per diluted share. Net operating cash flow was $515 million, or $672 million before changes in working capital.

Highlights

Generated $80 million of organic free cash flow post-dividend, and remains on track to achieve two-year organic free cash flow objectives
Executed $50 million of year-to-date share repurchases in addition to $41 million of dividend payments; $750 million of share repurchase authorization remaining
Development capital spend of $569 million, down 8% from year-ago quarter; annual $2.4 billion development capital budget remains unchanged
Total Company oil production averaged 203,000 net bopd, up 6% from year-ago quarter, divestiture-adjusted; U.S. oil production averaged 177,000 net bopd, up 11% from year-ago quarter, divestiture-adjusted
Eagle Ford production averaged 105,000 net boed; 41 wells achieved an average 30-day IP rate of 1,515 boed (62% oil) at an average completed well cost of approx. $4.4 million
Bakken production averaged 92,000 net boed; 29 wells achieved an average 30-day IP rate of 2,500 boed (77% oil) at an average completed well cost of approx. $5.1 million
Oklahoma production averaged 63,000 net boed; successful over-pressured STACK development continues at optimized spacing designs, with infill pads developed at three, six and eight wells per section equivalent spacing delivering an average 30-day IP rate of 1,870 boed (53% oil)
Northern Delaware production averaged 26,000 net boed; 15 wells achieved an average 30-day IP rate of 1,815 boed (65% oil), or 360 boed per 1,000 foot lateral
Portfolio optimization continues with agreement for divestiture of U.K. business, including approx. $950 million of asset retirement obligations
Strong financial position with total liquidity of $4.4 billion as of March 31; investment grade at all three major ratings agencies following recent upgrade by Moody's Investor Services, Inc.

"First quarter featured strong execution across our advantaged multi-basin portfolio and was highlighted by solid well productivity and improving well costs in each of our basins," said Chairman, President and CEO Lee Tillman. "We remain fully committed to our well-established framework for success: improving bottom-line corporate returns, generating sustainable free cash flow with an organic break-even of only $45/bbl WTI, prioritizing return of capital to shareholders, and enhancing our capital efficiency and underlying resource base through differentiated execution. We've returned over $90 million to shareholders year-to-date, more than fully funded by organic free cash flow. As we look forward to second quarter, strong April performance underpins our confidence in expected 5% sequential U.S. oil growth. With this significant operational momentum, we expect returns and free cash flow generation to inflect higher while our capital spending plans remain unchanged."

U.S.

U.S. production averaged 296,000 net barrels of oil equivalent per day (boed) for first quarter 2019, including 177,000 net barrels of oil per day (bopd). Oil production was up 11% from the year-ago quarter on a divestiture-adjusted basis, despite extreme weather conditions experienced during first quarter 2019. U.S. unit production costs were $5.21 per barrel of oil equivalent (boe), down 12% from the year-ago quarter due to ongoing cost reductions across the U.S. resource plays, particularly in the Northern Delaware.

EAGLE FORD: Marathon Oil's Eagle Ford production averaged 105,000 net boed in the first quarter. The Company brought 41 gross Company-operated wells to sales in the quarter with an average 30-day initial production (IP) rate of 1,515 boed (62% oil) at an average completed well cost of $4.4 million.

BAKKEN: Marathon Oil's Bakken production averaged 92,000 net boed in the first quarter. The Company brought 29 gross Company-operated wells to sales with an average 30-day IP rate of 2,500 boed (77% oil) at an average completed well cost of $5.1 million. First quarter 2019 activity was primarily concentrated in Myrmidon. The Company continues to enhance its Williston Basin footprint, recently executing a small bolt-on acquisition and additional leasing that has added more than 50 Company-operated locations to inventory.

OKLAHOMA: Marathon Oil's Oklahoma production averaged 63,000 net boed in the first quarter. The Company brought 18 gross Company-operated wells to sales, with 16 of these wells brought to sales during March. In the STACK, the Company again realized strong over-pressured Meramec infill drilling results through optimized development at the drill spacing unit level. Three infill pads developed at three, six, and eight wells per section equivalent spacing delivered an average 30-day IP rate of 1,870 boed (53% oil), with completed well cost per lateral foot down more than 30% relative to parent wells.

NORTHERN DELAWARE: Marathon Oil's Northern Delaware production averaged 26,000 net boed in the first quarter. The Company brought 15 gross Company-operated wells to sales with an average 30-day IP rate of 1,815 boed (65% oil), or 360 boed per 1,000 foot lateral. First quarter 2019 wells to sales featured a mix of early development and delineation drilling across both the Malaga and Red Hills areas. In Malaga, a four-well pad targeting the Bone Spring, Upper Wolfcamp and Lower Wolfcamp horizons achieved a 30-day IP rate of 2,830 boed (62% oil), or 400 boed per 1,000 foot lateral.

International

International production averaged 92,000 net boed for first quarter 2019. During the quarter, the Company successfully completed its planned triennial turnaround in E.G., with a return to full production levels achieved on schedule in early April. First quarter 2019 International unit production costs averaged $6.22 per boe.

The Company recently signed a definitive agreement to process third-party Alen Unit gas through existing infrastructure located in Punta Europa, E.G., a significant step toward solidifying Punta Europa as a cornerstone component of the E.G. Gas Mega Hub for the potential development of local and regional natural gas. First gas sales from the Alen Unit is expected in 2021, and will utilize available processing capacity not required by the Alba Field. Marathon Oil is the operator and majority shareholder of the integrated gas business at Punta Europa and will maintain market exposure through a combination of both profit sharing and tolling.

The Company signed an agreement for the divestiture of its U.K. business, with an expected close during the second half of 2019, a transaction which will mark a complete country exit. Marathon Oil's U.K. properties include approximately $950 million of asset retirement obligations and are classified as held for sale in the consolidated balance sheet as of March 31. U.K. held for sale assets of $947 million, including $323 million of cash and cash equivalents, will be partially offset at close by sales proceeds of approximately $140 million.

Cash Flow, Development Capital and Resource Capture

Net cash provided by operations was $515 million during first quarter 2019, or $672 million before changes in working capital. First quarter development capital expenditures were $569 million. The Company's 2019 development capital budget remains unchanged at $2.4 billion. Outside of the development capital budget, first quarter resource play leasing and exploration (REx) capital expenditures were $37 million. The Company's 2019 REx capital budget also remains unchanged at $200 million.

Production Guidance

For second quarter 2019, the Company forecasts total oil production of 200,000 to 220,000 net bopd, with U.S. oil production of 180,000 to 190,000 net bopd. Second quarter U.S. oil production is expected to increase 5% sequentially at the midpoint of guidance, reflecting strong operational momentum already achieved early in the quarter. Second quarter 2019 international oil production guidance of 20,000 to 30,000 net bopd reflects continued unscheduled downtime at the non-operated Foinaven complex. Previously provided full-year 2019 production guidance, calling for total Company oil production growth of 10%, with U.S. oil growth of 12%, remains unchanged.

Corporate

The Company has executed $50 million of year-to-date share repurchases, returning additional capital to shareholders beyond the $41 million first quarter dividend payment. Share repurchases have been more than fully funded by post-dividend organic free cash flow, and $750 million remains on current authorization.

Total liquidity as of March 31 was approximately $4.4 billion, which consisted of $1.0 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.4 billion. End of quarter cash and cash equivalents reflect cash balances classified as held for sale associated with U.K. properties, but do not include expected sales proceeds to be received at close. The company is rated investment grade at all three major credit ratings agencies following a recent upgrade by Moody's Investor Services, Inc.

The adjustments to net income for first quarter 2019 totaled $89 million before tax, primarily due to the income impact associated with unrealized losses on derivative instruments, partially offset by a gain on sale related to working interest in the Gulf of Mexico Droshky field. In addition, first quarter adjusted net income of $256 million included a tax benefit and indemnification income totaling $168 million.

As of April 30, the Company's open crude hedge positions for 2019 include an average of 76,691 bopd at a weighted average floor price of $56.48 and a weighted average ceiling price of $73.29, hedged through three-way collars.

A slide deck and Quarterly Investor Packet will be posted to the Company's website following this release today, May 1. On Thursday, May 2, at 9:00 a.m. ET, the Company will conduct a question and answer webcast/call, which will include forward-looking information. The live webcast, replay and all related materials will be available at https://www.marathonoil.com/Investors.

Definitions

Organic free cash flow - Operating cash flow before working capital (excluding exploration costs other than well costs), less development capital expenditures, less dividends, plus other.

Non-GAAP Measures

In analyzing and planning for its business, Marathon Oil supplements its use of GAAP financial measures with non-GAAP financial measures, including adjusted net income, adjusted net income per share, net cash provided by operations before changes in working capital, and organic free cash flow because the Company believes this information is useful to investors to help evaluate the Company's financial performance between periods and to compare the Company's performance to certain competitors. Management also uses net cash provided by operations before changes in working capital to demonstrate the Company's ability to internally fund capital expenditures, pay dividends and service debt. The Company considers adjusted net income, adjusted income from operations, adjusted net income per share and adjusted income from operations per share as another way to meaningfully represent the Company's operational performance for the period presented; consequently, it excludes the impact of mark-to-market accounting, impairment charges, dispositions, pension settlements, and other items that could be considered "non-operating" or "non-core" in nature. These non-GAAP financial measures reflect an additional way of viewing aspects of the business that, when viewed with GAAP results may provide a more complete understanding of factors and trends affecting the business and are a useful tool to help management and investors make informed decisions about Marathon Oil's financial and operating performance. These measures should not be considered substitutes for their most directly comparable GAAP financial measures. A reconciliation to their most directly comparable GAAP financial measures can be found in our investor package on our website at www.marathonoil.com and in the tables below. Marathon Oil strongly encourages investors to review the Company's consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

Forward-looking Statements

This release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, including without limitation statements regarding the Company's 2019 capital budget and allocations (including development capital budget and resource play leasing and exploration spend), future performance, organic free cash flow, free cash flow, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production guidance, cash margins, asset sales and acquisitions, leasing and exploration activities, production, oil growth and other plans and objectives for future operations, are forward-looking statements. Words such as "anticipate," "believe," "could," "estimate," "expect," "forecast," "guidance," "intend," "may," "plan," "project," "seek," "should," "target," "will," "would," or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While the Company believes its assumptions concerning future events are reasonable, a number of factors could cause actual results to differ materially from those projected, including, but not limited to: conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price; changes in expected reserve or production levels; changes in political or economic conditions in the jurisdictions in which the Company operates; risks related to the Company's hedging activities; capital available for exploration and development; drilling and operating risks; well production timing; availability of drilling rigs, materials and labor, including associated costs; difficulty in obtaining necessary approvals and permits; non-performance by third parties of contractual obligations; unforeseen hazards such as weather conditions, acts of war or terrorist acts and the government or military response thereto; cyber-attacks; changes in safety, health, environmental, tax and other regulations; other geological, operating and economic considerations; and the risk factors, forward-looking statements and challenges and uncertainties described in the Company's 2018 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at www.marathonoil.com. Except as required by law, the Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

Media Relations Contact:
Lee Warren: 713-296-4103

Investor Relations Contacts:
Guy Baber: 713-296-1892
John Reid: 713-296-4380

Consolidated Statements of Income (Unaudited)	Three Months Ended
	Mar. 31		Dec. 31		Mar. 31
(In millions, except per share data)	2019		2018		2018
Revenues and other income:
Revenues from contracts with customers	$	1,200	$	1,380	$	1,537
Net gain (loss) on commodity derivatives	(91)		310		(102)
Income from equity method investments	11		64		37
Net gain (loss) on disposal of assets	42		(4)		257
Other income	35		15		4
Total revenues and other income	1,197		1,765		1,733
Costs and expenses:
Production	187		205		217
Shipping, handling and other operating	154		167		130
Exploration	59		116		52
Depreciation, depletion and amortization	554		613		590
Impairments	6		25		8
Taxes other than income	72		84		64
General and administrative	94		88		100
Total costs and expenses	1,126		1,298		1,161
Income from operations	71		467		572
Net interest and other	(49)		(58)		(45)
Other net periodic benefit costs	5		(3)		(3)
Income before income taxes	27		406		524
Provision (benefit) for income taxes	(147)		16		168
Net income	$	174	$	390	$	356

Adjusted Net Income
Net income	$	174	$	390	$	356
Adjustments for special items (pre-tax):
Net (gain) loss on disposal of assets	(42)		4		(257)
Proved property impairments	6		25		8
Exploratory dry well costs, unproved property impairments and other	—		40		—
Pension settlement	—		5		4
Unrealized (gain) loss on derivative instruments	113		(336)		43
Other	12		6		—
Benefit for income taxes related to special items	(7)		(13)		—
Adjustments for special items	$	82	$	(269)	$	(202)
Adjusted net income (a)	$	256	$	121	$	154
Per diluted share:
Net income	$	0.21	$	0.47	$	0.42
Adjusted net income (a)	$	0.31	$	0.15	$	0.18
Weighted average diluted shares	820		829		852
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended
	Mar. 31		Dec. 31		Mar. 31
(In millions)	2019		2018		2018
Segment income
United States	$	132	$	159	$	125
International	61		83		132
Segment income	193		242		257
Not allocated to segments	(19)		148		99
Net income	$	174	$	390	$	356
Exploration expenses
United States	$	59	$	76	$	51
International	—		—		1
Segment exploration expenses	59		76		52
Not allocated to segments	—		40		—
Total	$	59	$	116	$	52
Cash flows
Net cash provided by operating activities	$	515	$	855	$	649
Minus: changes in working capital	(157)		68		(83)
Net cash provided by operations before changes in working capital (a)	$	672	$	787	$	732

Cash additions to property, plant and equipment	$	(615)	$	(684)	$	(662)
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended
(In millions)	Mar. 31, 2019
Organic Free Cash Flow
Net cash provided by operating activities	$	515
Minus: changes in working capital	(157)
Minus: exploration costs other than well costs	(10)
Development capital expenditures	(569)
Dividends	(41)
EG LNG return of capital and other	8
Organic free cash flow (a)	$	80
(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended
	Mar. 31	Dec. 31	Mar. 31
(mboed)	2019	2018	2018
Net production
United States	296	306	284
International, excluding Libya (a)	92	105	114
Total net production, excluding Libya (a)	388	411	398
Libya (a)	—	—	28
Total net production	388	411	426
(a) The Company closed on the sale of its Libya subsidiary in first quarter 2018.

Supplemental Statistics (Unaudited)	Three Months Ended
	Mar. 31	Dec. 31	Mar. 31
(mboed)	2019	2018	2018
Net production
United States	296	306	284
Less: Divestitures (a)	—	—	7
Total divestiture-adjusted United States	296	306	277

International	92	105	142
Less: Divestitures (b)	—	—	30
Total divestiture-adjusted International	92	105	112

Total net production divestiture-adjusted (a)(b)	388	411	389

(a)

The Company closed on the sale of certain United States non-core conventional assets

primarily in the Gulf of Mexico in third quarter 2018 and first quarter 2019. The production

volumes relating to these dispositions have been removed from all corresponding prior

periods to derive the divestiture-adjusted United States net production.

(b)

Divestitures include the following: (1) volumes associated with Libya which closed in first

quarter 2018 and (2) volumes associated with the sale of certain non-core International

assets which closed in third quarter 2018. These production volumes have been removed

from historical periods above in arriving at total divestiture-adjusted International net

production.

Supplemental Statistics (Unaudited)	Three Months Ended
	Mar. 31	Dec. 31	Mar. 31
	2019	2018	2018
United States - net sales volumes
Crude oil and condensate (mbbld)	177	180	164
Eagle Ford	61	62	63
Bakken	79	82	61
Oklahoma	16	16	20
Northern Delaware	15	14	10
Other United States (a)	6	6	10
Natural gas liquids (mbbld)	55	55	50
Eagle Ford	23	24	21
Bakken	7	6	7
Oklahoma	18	19	18
Northern Delaware	6	5	3
Other United States (a)	1	1	1
Natural gas (mmcfd)	392	422	420
Eagle Ford	127	127	122
Bakken	36	35	35
Oklahoma	173	192	216
Northern Delaware	33	42	17
Other United States (a)	23	26	30
Total United States (mboed)	297	305	284
International - net sales volumes
Crude oil and condensate (mbbld)	23	29	63
Equatorial Guinea	12	16	15
United Kingdom	9	10	15
Libya (b)	—	—	28
Other International	2	3	5
Natural gas liquids (mbbld)	8	10	11
Equatorial Guinea	8	10	11
Natural gas (mmcfd)	342	411	437
Equatorial Guinea	330	400	403
United Kingdom (c)	12	11	12
Libya (b)	—	—	22
Total International (mboed)	88	108	147
Total Company - net sales volumes (mboed)	385	413	431
Net sales volumes of equity method investees
LNG (mtd)	4,636	5,384	5,541
Methanol (mtd)	1,003	1,119	1,195
Condensate and LPG (boed)	9,890	15,071	12,416

(a)

The three months ended March 31, 2018 includes sales volumes from the sale of certain

United States non-core conventional assets primarily in the Gulf of Mexico which closed

in third quarter 2018.

(b)

The Company closed on the sale of its Libya subsidiary in first quarter 2018.

(c)

Includes natural gas acquired for injection and subsequent resale.

Supplemental Statistics (Unaudited)	Three Months Ended
	Mar. 31		Dec. 31		Mar. 31
	2019		2018		2018
United States - average price realizations (a)
Crude oil and condensate ($ per bbl) (b)	$	54.05	$	56.01	$	62.22
Eagle Ford	57.69		63.27		64.37
Bakken	52.15		51.11		60.20
Oklahoma	53.39		58.42		62.70
Northern Delaware	48.97		48.04		60.45
Other United States (c)	56.19		60.41		61.71
Natural gas liquids ($ per bbl)	$	15.66	$	24.71	$	22.95
Eagle Ford	17.05		21.46		22.85
Bakken	16.17		19.01		23.57
Oklahoma	13.66		29.55		22.59
Northern Delaware	15.27		28.99		22.11
Other United States (c)	18.92		26.68		28.66
Natural gas ($ per mcf) (d)	$	2.93	$	3.27	$	2.59
Eagle Ford	2.99		3.69		3.03
Bakken	3.77		3.46		3.25
Oklahoma	2.90		3.22		2.20
Northern Delaware	1.93		1.80		3.09
Other United States (c)	2.89		3.65		2.64
International - average price realizations
Crude oil and condensate ($ per bbl)	$	53.93	$	58.25	$	66.23
Equatorial Guinea	44.36		46.35		51.94
United Kingdom	67.62		78.49		69.95
Libya (e)	—		—		73.75
Other International	47.76		52.52		55.29
Natural gas liquids ($ per bbl)	$	1.96	$	2.25	$	1.83
Equatorial Guinea (f)	1.00		1.00		1.00
United Kingdom	38.10		33.44		44.53
Natural gas ($ per mcf)	$	0.48	$	0.49	$	0.65
Equatorial Guinea (f)	0.24		0.24		0.24
United Kingdom	7.02		9.13		7.32
Libya (e)	—		—		4.57
Benchmark
WTI crude oil (per bbl)	$	54.90	$	59.34	$	62.89
Brent (Europe) crude oil (per bbl) (g)	$	63.17	$	67.71	$	66.81
Henry Hub natural gas (per mmbtu) (h)	$	3.15	$	3.64	$	3.00

(a)	Excludes gains or losses on commodity derivative instruments.
(b)	Inclusion of realized gains (losses) on crude oil derivative instruments would have affected average price realizations by $1.10, $(1.50) and $(4.33) for first quarter 2019, fourth quarter 2018, and first quarter 2018.
(c)	The three months ended March 31, 2018 includes sales volumes from the sale of certain United States non-core conventional assets primarily in the Gulf of Mexico in third quarter 2018.
(d)	Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal impact on average price realizations for the periods presented.
(e)	The Company closed on the sale of its Libya subsidiary in first quarter 2018.
(f)	Represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and/or Equatorial Guinea LNG Holdings Limited, which are equity method investees. The Alba Plant LLC processes the NGLs and then sells secondary condensate, propane, and butane at market prices. Marathon Oil includes its share of income from each of these equity method investees in the International segment.
(g)	Average of monthly prices obtained from Energy Information Administration website.
(h)	Settlement date average per mmbtu.

Q2 2019 Production Guidance	Oil Production (mbbld)				Equivalent Production (mboed)
	Q2 2019		Q1 2019	Q2 2018	Q2 2019		Q1 2019	Q2 2018
	Low	High	Divestiture -Adjusted (a)	Divestiture -Adjusted (a)	Low	High	Divestiture -Adjusted (a)	Divestiture -Adjusted (a)
Net production
United States	180	190	176	164	310	320	296	293
International	20	30	24	29	95	105	89	118
Total net production	200	220	200	193	405	425	385	411
(a) Divestiture-adjusted also removes volumes associated with the Atrush block in Kurdistan which is classified as held for sale.

The following tables set forth outstanding derivative contracts as of April 29, 2019, and the weighted average prices for those contracts:

	2019						2020		2021
*Crude Oil*	Second Quarter		Third Quarter		Fourth Quarter		Full Year		First Quarter
*NYMEX WTI Three-Way Collars ^(a)*
Volume (Bbls/day)	70,000		80,000		80,000		9,945		—
Weighted average price per Bbl:
Ceiling	$	71.21	$	74.19	$	74.19	$	70.00	—
Floor	$	55.86	$	56.75	$	56.75	$	55.00	—
Sold put	$	48.71	$	49.50	$	49.50	$	47.00	—
*Basis Swaps - Argus WTI Midland ^(b)*
Volume (Bbls/day)	10,000		15,000		15,000		15,000		—
Weighted average price per Bbl	$	(0.82)	$	(1.40)	$	(1.40)	$	(0.94)	—
*Basis Swaps - Net Energy Clearbrook ^(c)*
Volume (Bbls/day)	1,000		1,000		1,000		—		—
Weighted average price per Bbl	$	(3.50)	$	(3.50)	$	(3.50)	—		—
*Basis Swaps - NYMEX WTI / ICE Brent ^(d)*
Volume (Bbls/day)	5,000		5,000		5,000		5,000		3,278
Weighted average price per Bbl	$	(7.24)	$	(7.24)	$	(7.24)	$	(7.24)	$	(7.24)
*NYMEX Roll Basis Swaps*
Volume (Bbls/day)	60,000		60,000		60,000		—		—
Weighted average price per Bbl	$	0.38	$	0.38	$	0.38	—		—

(a)	Between April 1, 2019 and April 29, 2019, the Company entered into 20,000 Bbls/day and 20,000 Bbls/day of three-way collars for July - December 2019 and January - June 2020, respectively, with a ceiling of $70.00, a sold put of $47.00, and a floor of $55.00. The Company also entered into 10,000 Bbls/day of three-way collars for July - December 2019 with a ceiling of $74.09, a sold put of $48.00, and a floor of $55.00.
(b)	The basis differential price is indexed against Argus WTI Midland.
(c)	The basis differential price is indexed against Net Energy Canada Bakken SW at Clearbrook ("UHC").
(d)	The basis differential price is indexed against International Commodity Exchange ("ICE") Brent and NYMEX WTI.