Marathon Oil Reports Third Quarter 2018 Results

Multi-Basin Execution Drives Significant Free Cash Flow and Supports Enhanced Return of Cash to Shareholders; Capital Budget Unchanged with Full-Year Production Guidance Raised Again

News provided by

Marathon Oil Corporation

Nov 07, 2018, 16:30 ET

HOUSTON, Nov. 7, 2018 /PRNewswire/ -- Marathon Oil Corporation (NYSE: MRO) today reported third quarter 2018 net income of $254 million, or $0.30 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 $200 million, or $0.24 per diluted share. Net operating cash flow was $963 million, or $889 million before changes in working capital.

Highlights

Generated $320 million of organic free cash flow during third quarter, bringing year-to-date organic free cash flow generation to over $630 million
Executed $500 million of year-to-date share repurchases, returning additional capital to shareholders beyond existing $170 million annual dividend; $1 billion of repurchase authorization remaining
Raised both 2018 total Company and resource play oil and boe annual production guidance with no change to 2018 development capital budget; third quarter development capital expenditures down 8% sequentially with full-year resource play wells to sales trending slightly above the midpoint of guidance
Total third quarter production averaged 419,000 net boed, above the high end of guidance; total oil production averaged 204,000 net bopd, up 3% compared to the prior quarter on a divestiture adjusted basis
U.S. resource play third quarter production averaged 294,000 net boed, above the high end of guidance; oil production averaged 168,000 net bopd, up 4% compared to the prior quarter
Eagle Ford production increased to 115,000 net boed, up 8% sequentially; 12 wells to sales in the Atascosa County extended core averaged a 30-day IP rate of 1,400 boed (81% oil)
Bakken production averaged 85,000 net boed, up 4% sequentially, with oil production up 5%; 21 wells to sales averaged a 30-day IP rate of 3,460 boed (76% oil); basin leading performance continues with a six well West Myrmidon pad achieving an average 30-day IP rate of 4,745 boed (73% oil), three of which set new Three Forks Williston Basin records, including one well achieving a 30-day IP rate of 6,380 boed (75% oil); successful Hector Southern extension with two-well Lars pad achieving an average 30-day IP rate of 1,810 boed (83% oil)
Oklahoma production averaged 73,000 net boed; two successful STACK Meramec overpressured multi-well pads brought on-line, achieving average 30-day IP rates of 1,700 boed (65% oil) and 1,485 boed (63% oil), respectively
Northern Delaware production averaged 21,000 net boed, up 24% sequentially; 18 wells to sales averaged a 30-day IP rate of 1,285 boed (65% oil), or 285 boed per 1,000-foot lateral; a three-well Malaga pad in Eddy county averaged a 30-day IP rate of 2,275 boed (63% oil), or 540 boed per 1,000-foot lateral

"Another quarter of outstanding operational execution and capital efficiency across our multi-basin U.S. portfolio has again delivered production out-performance and enabled us to raise annual resource play production guidance for the third consecutive quarter, with no increase to our development capital budget. Each of our asset teams contributed to this strong outcome, highlighted by basin leading results and continued core extension in the Eagle Ford and Bakken, the successful transition to primarily multi-well pad development drilling in Oklahoma, and the progression of important multi-well tests alongside strategic advancements in the Northern Delaware," said Marathon Oil president and CEO Lee Tillman. "Consistent execution and our commitment to capital discipline have resulted in more than $630 million of year-to-date organic free cash flow generation, enabling us to return additional capital to shareholders through $500 million of share repurchases. At the same time, we maintained our focus on resource base enhancement, as evidenced by organic inventory upgrades in the Eagle Ford and Bakken, our successful participation in the recent New Mexico lease sale, and the spud of our first exploration well in the emerging Louisiana Austin Chalk play. We remain on track to deliver a strong rate of change in our key financial performance metrics, highlighted by an expected annual increase of 85 percent in corporate cash return on invested capital (CROIC) at $65/bbl WTI. Looking ahead to 2019, our framework for success will not change: a focus on corporate level returns, differentiated execution, free cash flow delivery at conservative oil prices, and the return of capital back to shareholders."

Development Capital
Third quarter development capital expenditures, before working capital, were $557 million, down 8 percent sequentially. Net cash provided by continuing operations was $963 million during third quarter 2018, or $889 million before changes in working capital. The Company's 2018 development capital budget remains unchanged at $2.3 billion.

Resource Capture
Outside of the development capital budget, total resource capture spending totaled $151 million during third quarter, including both Resource Play leasing and exploration (REx) and small bolt-on acquisitions. This year's resource capture spend has been more than fully funded through divestiture proceeds received in first quarter 2018.

Third quarter 2018 REx capital expenditures totaled $46 million, bringing year-to-date REx spend to $294 million. The Company spud its first Louisiana Austin Chalk exploration well, with results anticipated in 2019. Though episodic in nature, the Company anticipates REx capital expenditures of $50 to $100 million during fourth quarter 2018 representing no change to full-year REx capital spending guidance.

In the Northern Delaware the Company acquired 1,800 net acres in New Mexico for $105 million in the Bureau of Land Management (BLM) lease sale. These bolt-on leases include an attractive 12.5 percent royalty interest and a 10-year term, and are synergistic with the Company's existing footprint in the play.

Production Guidance
Marathon Oil expects fourth quarter 2018 U.S. production to average 295,000 to 305,000 net barrels of oil equivalent per day (boed). The Company expects fourth quarter 2018 U.S. resource play production to average 290,000 to 300,000 net boed, with oil production expected to increase approximately 5 percent sequentially despite a planned modest quarter-on-quarter reduction in wells to sales. Full-year wells to sales continues to trend slightly above the midpoint of guidance. Fourth quarter 2018 International production is expected to average 105,000 to 115,000 net boed, affected by the timing of planned maintenance in E.G.

The Company increased its annual 2018 total Company production guidance to 405,000 to 415,000 net boed, up from 400,000 to 415,000 net boed. The Company also raised its guidance for annual resource play oil and barrel of oil equivalent (boe) growth to 30 - 34 percent, up from 28 - 32 percent previously, with oil expected to be at the high end of the range. All guidance is adjusted to reflect the divestment of non-core U.S. assets that closed in July, and which contributed 1,000 boed (75% oil) to third quarter production, as well as an international asset sale that closed in August, and which contributed 1,400 boed to third quarter production (100% oil).

U.S. E&P
U.S. E&P production averaged 304,000 net boed for third quarter 2018, including oil production of 174,000 net barrels of oil per day (bopd). Oil production was up 5 percent compared to the prior quarter and up 28 percent from the year-ago quarter on a divestiture-adjusted basis. Third quarter production from the U.S. resource plays was 294,000 net boed, including oil production of 168,000 net bopd. Third quarter U.S. E&P unit production costs were $6.14 per boe. In July, the Company closed on the previously announced sales of its non-operated Gunflint and Troika assets in the Gulf of Mexico and a CO2 flood in West Texas, which collectively averaged production of 1,000 boed (76% oil) in third quarter 2018 and 5,000 net boed in the first half of the year (76% oil).

EAGLE FORD: Marathon Oil's Eagle Ford production averaged 115,000 net boed in the third quarter, compared to 106,000 net boed in the prior quarter. The Company brought 38 gross Company-operated wells to sales with an average 30-day initial production (IP) rate of 1,680 boed (63% oil), including 12 wells with an average 30-day IP rate of 1,400 boed (81% oil) in the extended core of Atascosa County. The Eagle Ford asset again generated significant free cash flow in the quarter through a combination of well performance and oil realizations above WTI due to strong LLS-based pricing.

BAKKEN: In third quarter 2018, Marathon Oil's Bakken production averaged 85,000 net boed, up 4 percent compared to 82,000 net boed in the prior quarter. Oil production was up 5 percent sequentially. The Company brought 21 gross Company-operated wells to sales with an average 30-day IP rate of 3,460 boed (76% oil), with activity primarily concentrated in Myrmidon. In West Myrmidon during third quarter, a six well pad achieved an average 30-day IP rate of 4,745 boed (73% oil). Three of these wells established new Three Forks Williston Basin records, including the Jerome well with an average 30-day IP rate of 6,380 boed (75% oil). The Company also continues to extend the core of its acreage position, with the two-well Lars pad in southern Hector achieving an average 30-day IP rate of 1,810 boed (83% oil) and plans are on track to test the Ajax area before year-end. Marathon Oil is in full compliance with state gas capture requirements, and anticipates no impact to forward development plans.

OKLAHOMA: Marathon Oil's Oklahoma production averaged 73,000 net boed during third quarter 2018, down from 80,000 net boed in the prior quarter, with only 11 wells brought to sales. This is consistent with the Company's successful transition from leasehold drilling to primarily multi-well pad development. In the STACK, the Company brought on two Meramec overpressured pads at different equivalent well spacing that illustrate the consistency and predictability of optimized development at the drill spacing unit (DSU) level. The Irven John infill pad on four wells per section equivalent spacing achieved an average 30-day IP rate of 1,700 boed (65% oil) and the HR Potter infill pad on seven wells per section equivalent spacing achieved an average 30-day IP rate of 1,485 boed (63% oil). Four of the new HR Potter wells were brought on at the end of third quarter, while the remaining wells were brought on subsequent to quarter end.

NORTHERN DELAWARE: Marathon Oil's Northern Delaware production increased to an average of 21,000 net boed in third quarter 2018, up 24 percent from the prior quarter. The Company brought 18 gross Company-operated wells to sales in the Malaga and Red Hills areas, a mix of development and appraisal wells with an average 30-day IP rate of 1,285 boed (65% oil), or 285 boed per 1,000 foot lateral. A three-well Malaga pad in Eddy county, which targeted Upper Wolfcamp horizons, reported an average 30-day IP rate of 2,275 boed (63% oil), or 540 boed per 1,000 foot lateral. The Company made important midstream advancements during third quarter to protect flow assurance, improve realizations and reduce expenses. Marathon Oil executed a two-year term oil sales agreement with a strategic buyer at attractive terms and signed a gas gathering and processing agreement covering the vast majority of Lea and Eddy county acreage. The Company continues to benefit from its Midland-Cushing basis swaps, with open positions that include 10,000 bopd hedged through remainder of 2018 and all of 2019, and 15,000 bopd hedged for full-year 2020, all at a discount of less than $1 to WTI.

International E&P
International E&P production averaged 115,000 net boed for third quarter 2018, down 4 percent compared to the prior quarter on a divestiture-adjusted basis. The decrease reflects maintenance activities in both E.G. and the U.K. In August, the Company closed on the previously announced sale of its non-operated interest in the Sarsang block in Kurdistan which produced 1,400 net boed in the third quarter and averaged 2,300 net boed through the first half of the year (100% oil). Third quarter 2018 International E&P unit production costs averaged $4.22 per boe.

During the third quarter the Company reduced the estimated cost of the U.K. asset retirement obligation (ARO) by $125 million, primarily due to the capture of favorable market conditions.

In addition to the previously referenced fourth quarter 2018 maintenance, a complete shutdown is planned for E.G. during first quarter 2019 to conduct planned turnaround activity.

Corporate
The Company has executed $500 million of year-to-date share repurchases, returning additional capital to shareholders beyond the existing $170 million annual dividend. Share repurchases have been more than fully funded by year-to-date organic free cash flow generation of over $630 million.

Total liquidity as of September 30 was approximately $5.0 billion, which consisted of $1.6 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.4 billion which was recently extended by one year to 2022.

The adjustments to net income for third quarter 2018 totaled $130 million before tax, primarily due to the income impact associated with the reduction in the U.K. ARO.

A slide deck and Quarterly Investor Packet will be posted to the Company's website following this release today, Nov. 7. On Thursday, Nov. 8, 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
CROIC - Cash return on invested capital; calculated by taking cash flow (operating cash flow before working capital + net interest after tax) divided by (average stockholder's equity + average net debt).
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 (loss), adjusted net income (loss) per share, net cash provided by continuing operations before changes in working capital, CROIC 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 continuing 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 (loss), adjusted income (loss) from continuing operations, adjusted net income (loss) per share and adjusted income (loss) from continuing 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 2018 capital budget and allocations, future performance, organic free cash flow, corporate-level cash returns on invested capital, business strategy, asset quality, drilling plans, production guidance, cash margins, rates of change for CROIC, asset sales and acquisitions, leasing and exploration activities, production, 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 2017 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
	Sept. 30		June 30		Sept. 30
(In millions, except per share data)	2018		2018		2017
Revenues and other income:
Revenues from contracts with customers	$	1,538	$	1,447	$	1,136
Net gain (loss) on commodity derivatives	(70)		(152)		(22)
Marketing revenues	—		—		48
Income from equity method investments	64		60		63
Net gain (loss) on disposal of assets	16		50		19
Other income	119		12		8
Total revenues and other income	1,667		1,417		1,252
Costs and expenses:
Production	215		205		197
Marketing, including purchases from related parties	—		—		49
Shipping, handling and other operating	152		126		109
Exploration	56		65		294
Depreciation, depletion and amortization	626		612		641
Impairments	8		34		201
Taxes other than income	86		65		44
General and administrative	101		105		89
Total costs and expenses	1,244		1,212		1,624
Income (loss) from operations	423		205		(372)
Net interest and other	(58)		(65)		(35)
Other net periodic benefit costs	(8)		—		(5)
Loss on early extinguishment of debt	—		—		(46)
Income (loss) from operations before income taxes	357		140		(458)
Provision (benefit) for income taxes	103		44		141
Net income (loss)	$	254	$	96	$	(599)

Adjusted Net Income (Loss)
Net income (loss)	254		96		(599)
Adjustments for special items (pre-tax):
Net (gain) loss on disposal of assets	(16)		(50)		(19)
Proved property impairments	8		34		201
Exploratory dry well costs, unproved property impairments and other	—		—		250
Pension settlement	10		2		8
Unrealized (gain) loss on derivative instruments	(19)		45		56
Reduction of U.K. ARO estimated costs	(113)		(8)		—
Other	—		—		(5)
Provision (benefit) for income taxes related to special items	76		7		40
Adjustments for special items	$	(54)	$	30	$	531
Adjusted net income (loss) (a)	$	200	$	126	$	(68)
Per diluted share:
Net income (loss)	$	0.30	$	0.11	$	(0.70)
Adjusted net income (loss) (a)	$	0.24	$	0.15	$	(0.08)
Weighted average diluted shares	849		855		850

(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended
	Sept. 30		June 30		Sept. 30
(in millions)	2018		2018		2017
Segment income (loss)
United States E&P	$	201	$	123	$	(38)
International E&P	116		142		104
Segment income (loss)	317		265		66
Not allocated to segments	(63)		(169)		(665)
Net income (loss)	$	254	$	96	$	(599)
Exploration expenses
United States E&P	$	55	$	64	$	41
International E&P	1		1		3
Segment exploration expenses	56		65		44
Not allocated to segments	—		—		250
Total	$	56	$	65	$	294
Cash flows
Net cash provided by operating activities	$	963	$	767	$	564
Minus: changes in working capital	74		(82)		62
Total net cash provided from operations before changes in working capital (a)	$	889	$	849	$	502

Cash additions to property, plant and equipment	$	(769)	$	(638)	$	(530)

(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended		Nine Months Ended
(in millions)	Sept. 30, 2018		Sept. 30, 2018
Organic Free Cash Flow
Net cash provided by operating activities	$	963	$	2,379
Development capital expenditures	(557)		(1,783)
Dividends	(43)		(128)
Less changes in working capital	(74)		66
Exploration costs other than well costs	5		29
EG LNG return of capital & other	25		69
Organic free cash flow (a)	$	319	$	632

(a) Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended
	Sept. 30	June 30	Sept. 30
(mboed)	2018	2018	2017
Net production
United States E&P	304	298	245
International E&P, excluding Libya (a)	115	121	126
Total net production, excluding Libya (a)	419	419	371
Libya (a)	—	—	23
Total net production	419	419	394

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





Supplemental Statistics (Unaudited)	Three Months Ended
	Sept. 30	June 30	Sept. 30
(mboed)	2018	2018	2017
Net production
United States E&P	304	298	245
Less: Divestitures (a)	1	4	8
Total divestiture-adjusted United States E&P	303	294	237

International E&P	115	121	149
Less: Divestitures (b)	1	2	24
Total divestiture-adjusted International E&P	114	119	125

Total net production divestiture-adjusted (a)(b)	417	413	362


(a)	We closed on the sale of certain United States E&P non-core conventional assets primarily in the Gulf of Mexico in the third quarter of 2018, Oklahoma and Colorado in the third quarter of 2017. These production volumes have been removed from all historical periods shown in arriving at total divestiture-adjusted United States E&P net production.

(b)	The Company closed on the sale of its Libya subsidiary in the first quarter 2018. Additionally, divestitures include the sale of certain non-core International E&P assets which closed in the third quarter of 2018. These production volumes have been removed from all historical periods shown in arriving at total divestiture-adjusted International E&P net production.

Supplemental Statistics (Unaudited)	Three Months Ended
	Sept. 30	June 30	Sept. 30
	2018	2018	2017
United States E&P - net sales volumes
Crude oil and condensate (mbbld)	173	168	139
Eagle Ford	66	63	58
Bakken	72	69	49
Oklahoma	18	18	17
Northern Delaware	12	11	6
Other United States (a)	5	7	9
Natural gas liquids (mbbld)	58	57	44
Eagle Ford	26	22	22
Bakken	6	7	6
Oklahoma	21	24	14
Northern Delaware	4	3	—
Other United States (a)	1	1	2
Natural gas (mmcfd)	433	435	369
Eagle Ford	137	127	126
Bakken	36	35	26
Oklahoma	208	230	161
Northern Delaware	30	18	15
Other United States (a)	22	25	41
Total United States E&P (mboed)	303	298	244
International E&P - net sales volumes
Crude oil and condensate (mbbld)	27	32	68
Equatorial Guinea	18	18	27
United Kingdom	6	10	15
Libya (b)	—	—	23
Other International	3	4	3
Natural gas liquids (mbbld)	11	12	13
Equatorial Guinea	11	11	12
United Kingdom	—	1	1
Natural gas (mmcfd)	441	461	507
Equatorial Guinea	426	443	482
United Kingdom (c)	15	18	25
Total International E&P (mboed)	112	121	165
Total Company - net sales volumes (mboed)	415	419	409
Net sales volumes of equity method investees
LNG (mtd)	6,152	6,141	6,943
Methanol (mtd)	1,334	1,316	1,366
Condensate and LPG (boed)	11,942	12,689	17,216


(a)	Includes sales volumes from the sale of certain United States E&P non-core conventional assets primarily in the Gulf of Mexico in the third quarter of 2018, Oklahoma and Colorado in the third quarter of 2017, respectively.

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

(c)	Includes natural gas acquired for injection and subsequent resale.

Supplemental Statistics (Unaudited)	Three Months Ended
	Sept. 30		June 30		Sept. 30
	2018		2018		2017
United States E&P - average price realizations (a)
Crude oil and condensate ($ per bbl) (b)	$	68.51	$	66.03	$	46.65
Eagle Ford	72.00		68.77		47.56
Bakken	67.26		64.41		46.06
Oklahoma	70.14		66.90		46.39
Northern Delaware	55.01		60.01		44.49
Other United States (c)	66.67		64.42		45.83
Natural gas liquids ($ per bbl)	$	28.07	$	22.09	$	20.86
Eagle Ford	28.62		22.68		19.52
Bakken	31.92		25.52		17.89
Oklahoma	25.29		20.75		23.58
Northern Delaware	31.44		19.10		30.23
Other United States (c)	34.71		25.62		24.94
Natural gas ($ per mcf) (d)	$	2.55	$	2.18	$	2.71
Eagle Ford	2.84		2.82		2.83
Bakken	2.64		2.46		2.08
Oklahoma	2.40		1.84		2.69
Northern Delaware	2.24		1.48		3.00
Other United States (c)	2.48		2.11		2.67
International E&P - average price realizations
Crude oil and condensate ($ per bbl)	$	64.08	$	66.12	$	51.23
Equatorial Guinea	61.23		60.30		46.91
United Kingdom	73.28		77.15		51.72
Libya (e)	—		—		56.93
Other International	62.30		64.73		40.67
Natural gas liquids ($ per bbl)	$	2.04	$	2.91	$	2.25
Equatorial Guinea (f)	1.00		0.99		1.00
United Kingdom	50.37		43.20		32.58
Natural gas ($ per mcf)	$	0.50	$	0.52	$	0.51
Equatorial Guinea (f)	0.24		0.24		0.24
United Kingdom	8.60		7.39		5.71
Benchmark
WTI crude oil (per bbl)	$	69.43	$	67.91	$	48.20
Brent (Europe) crude oil (per bbl)(g)	$	75.22	$	74.50	$	52.11
Henry Hub natural gas (per mmbtu)(h)	$	2.90	$	2.80	$	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 $(5.70), $(7.04), and $2.42, for the third and second quarter of 2018, and third quarter of 2017.

(c)	Includes sales volumes from the sale of certain United States E&P non-core conventional assets primarily in the Gulf of Mexico in the third quarter of 2018, Oklahoma and Colorado in the third quarter of 2017, respectively.

(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 the 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 E&P segment.

(g)	Average of monthly prices obtained from Energy Information Administration website.

(h)	Settlement date average per mmbtu.

The following tables set forth outstanding derivative contracts as of November 5, 2018 and the weighted average prices for those contracts:

*Crude Oil*	4Q 2018	FY 2019	FY 2020
*Three-Way Collars*
Volume (Bbls/day)	95,000	60,000	—
Weighted average price per Bbl:
Ceiling	$57.65	$73.18	—
Floor	$52.11	$56.67	—
Sold put	$45.21	$49.59	—
*Basis Swaps ^(a)*
Volume (Bbls/day)	10,000	10,000	15,000
Weighted average price per Bbl	$(0.67)	$(0.82)	$(0.94)
*NYMEX Roll Basis Swaps*
Volume (Bbls/day)	—	60,000	—
Weighted average price per Bbl	—	$0.38	—

*Natural Gas*	4Q 2018	1Q 2019
*Three-Way Collars ^(b)*
Volume (MMBtu/day)	160,000	100,000	—
Weighted average price per MMBtu:
Ceiling	$3.61	$3.75	—
Floor	$3.00	$3.00	—
Sold put	$2.50	$2.50	—

(a) The basis differential price is between WTI Midland and WTI Cushing.