Marathon Oil Reports Second Quarter 2018 Results

Continued Strong Multi-Basin Execution Drives Returns and Production Beat; Full-Year Guidance Raised with Budget Unchanged

News provided by

Marathon Oil Corporation

Aug 01, 2018, 16:30 ET

HOUSTON, Aug. 1, 2018 /PRNewswire/ -- Marathon Oil Corporation (NYSE: MRO) today reported second quarter 2018 net income of $96 million, or $0.11 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 $126 million, or $0.15 per diluted share. Net operating cash flow was $767 million, or $849 million before changes in working capital.

Highlights

Total production averaged 419,000 net boed; U.S. production averaged 298,000 net boed, both up 5% (ex-Libya) compared to the prior quarter
U.S. resource plays averaged 285,000 net boed, up 6% compared to the prior quarter with all four basins growing sequentially
Eagle Ford production increased to 106,000 net boed, up 2% sequentially; 39 wells to sales had an average 30-day initial production (IP) rate of 1,880 boed (66% oil)
Bakken production averaged 82,000 net boed, up 11% sequentially, with oil production up 14%; 21 wells to sales averaged a 30-day IP rate of 2,700 boed (77% oil); Winona and Mamie wells in West Myrmidon set new basin Three Forks records on 30-day IP oil rate; three new Elk Creek wells averaged a 30-day IP rate of 2,530 boed (72% oil)
Oklahoma production averaged 80,000 net boed, up 7% sequentially; four-well Lightner SCOOP Woodford infill pad delivered an average 30-day IP rate of 2,620 boed (48% oil) on equivalent eight-well per section spacing
Northern Delaware production averaged 17,000 net boed; six new wells from the Cypress infill pilot averaged 1,235 boed IP 30 (52% oil) and the three-well Fiddle Fee pad averaged 1,745 boed IP 30 (66% oil); executed agreement for water gathering and disposal in Eddy County
In July, closed on the sale of three non-core, non-operated conventional assets in the U.S., including two in the Gulf of Mexico, further concentrating and simplifying the portfolio
Raised both 2018 total Company oil and boe production guidance and 2018 resource play oil and boe production guidance, with no change to 2018 development capital budget

"Another quarter of outstanding operational execution across our multi-basin U.S. portfolio has driven better than expected production in the resource plays, and has enabled us to raise our annual resource play production guidance for the second consecutive quarter with no increase to our development capital budget. Our Eagle Ford and Bakken asset teams continue to set the standard for performance in their respective basins, while our Oklahoma and Northern Delaware assets progress important multi-well infill tests," said Marathon Oil president and CEO Lee Tillman. "Additionally, we continue to benefit from about half of our oil production for the quarter being linked to LLS or Brent, and the flexibility afforded by our differentiated position in the four best U.S. unconventional plays. In the second half of the year, we plan to drill our first exploration well in the emerging Louisiana Austin Chalk play as we continue our pursuit of low entry cost opportunities to enhance full-cycle returns. Our focus remains on execution and capital discipline, and we generated more than $250 million in organic free cash flow in the second quarter. We remain on track to deliver a strong rate of change in our key financial performance metrics highlighted by an expected annual increase of more than 70 percent in corporate cash return on invested capital (CROIC) at current strip prices."

Development Capital
Second quarter development capital expenditures, before working capital, were $608 million. Net cash provided by continuing operations was $767 million during second quarter 2018, or $849 million before changes in working capital. The Company's 2018 development capital budget remains at $2.3 billion with capital in the second half of the year moderating primarily due to reduced working interest consistent with planned well mix in the resource plays.

Resource Capture
Outside of the development capital budget, second quarter resource play leasing and exploration (REx) capital expenditures peaked for the year at $154 million. First half of the year spend of $248 million was more than fully funded through the divestiture proceeds received in first quarter 2018. Year-to-date, the Company has leased approximately 240,000 net acres in the emerging Louisiana Austin Chalk play. Though episodic in nature, the Company anticipates REx capital expenditures of $100 to $150 million in the second half of 2018 for continued leasing, exploration drilling and 3D seismic acquisition.

Production Guidance
Marathon Oil expects third quarter 2018 U.S. production to average 290,000 to 300,000 net barrels of oil equivalent per day (boed), which is adjusted for the sale of non-core, non-operated conventional U.S. assets that produced 4,200 net boed in the second quarter and averaged 5,000 net boed in the first half of the year (76% oil). The Company expects third quarter 2018 U.S. resource play production to average 280,000 to 290,000 net boed, consistent with planned timing of wells to sales and with sequential growth resuming in the fourth quarter. Third quarter 2018 International production is expected to average 105,000 to 115,000 net boed, lower than second quarter due to planned maintenance activity in E.G. and the U.K.

The Company increased its annual 2018 total Company production guidance to 400,000 to 415,000 net boed, up from 390,000 to 410,000 net boed. The Company also raised its guidance for annual resource play oil and barrel of oil equivalent (boe) growth to 28 - 32 percent, up from 25 - 30 percent previously.

U.S. E&P
U.S. E&P production averaged 298,000 net boed for second quarter 2018, up 5 percent compared to the prior quarter and up 36 percent from the year-ago quarter on a divestiture-adjusted basis. Second quarter production from the U.S. resource plays was 285,000 net boed, up from 269,000 net boed in the prior quarter. Second quarter U.S. E&P unit production costs were down just over 20 cents sequentially to $5.66 per boe and are expected to continue to moderate through 2018 as the Company accesses additional infrastructure in the Northern Delaware and as production volumes grow in the second half of the year. In July, the Company closed on the sales of its non-operated Gunflint and Troika assets in the Gulf of Mexico and a CO2 flood in West Texas. Combined, these assets produced 4,200 net boed in the second quarter, and averaged 5,000 net boed in the first half of the year (76% oil).

EAGLE FORD: Marathon Oil's Eagle Ford production averaged 106,000 net boed in the second quarter, compared to 104,000 net boed in the prior quarter. The Company brought 39 gross Company-operated wells to sales with an average 30-day IP rate of 1,880 boed (66% oil). The Company continued to deliver impressive results from core Karnes County, where the six-well Karnes City NE pad had an average 30-day IP rate of 2,330 boed (72% oil). The five-well Guajillo 10 South pad achieved an average 30-day IP rate of 1,660 boed (75% oil), further confirming the extension of core acreage into Atascosa County. The Eagle Ford asset 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 second quarter 2018, Marathon Oil's Bakken production averaged 82,000 net boed, up 11 percent compared to 74,000 net boed in the prior quarter. Oil production was up 14 percent sequentially. The Company brought 21 gross Company-operated wells to sales with an average 30-day IP rate of 2,700 boed (77% oil). Of these, 12 were in core Hector with an average 30-day IP rate of 2,285 boed (79% oil). As the Company continues its efforts to uplift performance outside the Myrmidon and Hector core, enhanced completion techniques were applied for the first time in Elk Creek with the three-well Bear Den pad achieving an impressive average 30-day IP rate of 2,530 boed (72% oil). In West Myrmidon, the Winona and the Mamie Three Forks wells set two new basin records delivering 30-day IP oil rates of 3,095 barrels of oil per day (bopd) and 3,090 bopd, respectively. Marathon Oil remains in full compliance with state gas capture requirements, and anticipates no impact to forward development plans.

OKLAHOMA: Marathon Oil's Oklahoma production averaged 80,000 net boed during second quarter 2018, up 7 percent from 75,000 net boed in the prior quarter. In the SCOOP, the Company brought on the four-well Woodford Lightner infill pad on 660-foot spacing across a half section, with an average 30-day IP rate of 2,620 boed (48% oil, 6,840-foot average lateral length). The pad's IP rate and oil cut both exceeded expectations. In the STACK, four Meramec wells in the Siegrist infill pad achieved an average 30-day IP rate of 900 boed (71% oil, 4,505-foot average lateral length), meeting expectations with strong oil rates. Marathon Oil also signed a firm transportation agreement for 100 million cubic feet per day beginning in fourth quarter 2018 to protect near-term natural gas production and bridge to the start-up of the Midship Pipeline on which Marathon Oil is an anchor shipper.

NORTHERN DELAWARE: Marathon Oil's Northern Delaware production increased to an average of 17,000 net boed in second quarter 2018, up 6 percent from the prior quarter. The Company brought 13 gross Company-operated wells to sales in the Malaga area in Eddy County, a mix of development and appraisal wells with an average 30-day IP rate of 1,130 boed (61% oil). The Cypress infill pilot, which targeted the Bone Spring, Upper Wolfcamp, and Lower Wolfcamp horizons, reported an average 30-day IP rate of 1,235 boed (52% oil; 60% oil excluding Lower Wolfcamp well). The three-well Fiddle Fee pad in the Bone Spring and Upper Wolfcamp reported an average 30-day IP rate of 1,745 boed (66% oil). Drilling efficiencies enabled the Company to reduce its rig count from five to four in the second quarter, without changing its full-year guidance of 50 to 55 gross operated wells to sales. In June, the Company executed an agreement with San Mateo for water gathering and disposal in Eddy County, which will significantly reduce unit production costs. The Company continues to benefit from its Midland-Cushing basis swaps, with open positions that include 10,000 bopd hedged for the second half 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. Additionally, the Company is in the process of finalizing a new term oil sales agreement in both Eddy and Lea counties.

International E&P
International E&P production averaged 121,000 net boed for second quarter 2018, up 6 percent compared to 114,000 net boed in the prior quarter excluding Libya. The increase reflects the completion of planned turnaround activity in E.G. in the first quarter. Second quarter 2018 International E&P unit production costs averaged $4.71 per boe, compared to $5.37 per boe in the prior quarter excluding Libya, due to the completion of the scheduled turnaround in E.G. in first quarter and fewer U.K. liftings in second quarter. The Company has signed agreements for the sales of its interest in the non-operated Sarsang and Atrush blocks in Kurdistan.

Corporate
Total liquidity as of June 30 was approximately $5.1 billion, which consisted of $1.7 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.4 billion.

Net income and adjusted net income in second quarter 2018 were negatively impacted by an increase in accrued expense of $14 million for stock-based performance units tied to the Company's improved total shareholder return, and $15 million in dry well and seismic expense.

The adjustments to net income for second quarter 2018 totaled $23 million before tax, primarily due to proved property impairments of $34 million associated with International and domestic conventional assets and an unrealized loss of $45 million on commodity derivatives, partially offset by a $50 million gain on sale that was primarily associated with acreage trading activity.

The Company maintained open hedges for the remainder of 2018, and during the second quarter increased its full-year 2019 open hedge positions to an average of 50,000 bopd at a weighted average floor price of $56.01 and a weighted average ceiling price of $71.74, using three-way collars.

A slide deck and Quarterly Investor Packet will be posted to the Company's website following this release today, Aug. 1. On Thursday, Aug. 2, at 10:00 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 income (loss) from continuing operations, adjusted net income (loss) per share, adjusted income (loss) from continuing operations 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
	June 30		Mar. 31		June 30
(In millions, except per share data)	2018		2018		2017
Revenues and other income:
Revenues from contracts with customers	$	1,447	$	1,537	$	902
Net gain (loss) on commodity derivatives	(152)		(102)		56
Marketing revenues	—		—		35
Income from equity method investments	60		37		51
Net gain (loss) on disposal of assets	50		257		6
Other income	12		4		9
Total revenues and other income	1,417		1,733		1,059
Costs and expenses:
Production	205		217		178
Marketing, including purchases from related parties	—		—		38
Shipping, handling and other operating	126		130		111
Exploration	65		52		30
Depreciation, depletion and amortization	612		590		592
Impairments	34		8		—
Taxes other than income	65		64		45
General and administrative	105		100		90
Total costs and expenses	1,212		1,161		1,084
Income (loss) from operations	205		572		(25)
Net interest and other	(65)		(45)		(86)
Other net periodic benefit costs	—		(3)		(1)
Income (loss) from continuing operations before income taxes	140		524		(112)
Provision (benefit) for income taxes	44		168		41
Income (loss) from continuing operations	96		356		(153)
Income (loss) from discontinued operations (a)	—		—		14
Net income (loss)	$	96	$	356	$	(139)

Adjusted Net Income
Income (loss) from continuing operations	96		356		(153)
Adjustments for special items from continuing operations (pre-tax):
Net (gain) loss on dispositions	(50)		(257)		(6)
Proved property impairments	34		8		—
Pension settlement	2		4		3
Unrealized (gain) loss on derivative instruments	45		43		(43)
Other	(8)		—		(3)
Provision (benefit) for income taxes related to special items from continuing operations	7		—		—
Adjustments for special items from continuing operations:	$	30	$	(202)	$	(49)
Adjusted income (loss) from continuing operations (b)	$	126	$	154	$	(202)
Income (loss) from discontinued operations (a)	—		—		14
Adjustments for special items from discontinued operations (pre-tax):
Net (gain) loss on disposition (a)	—		—		43
Provision (benefit) for income taxes related to special items from discontinued operations (a)	—		—		—
Adjusted net income (loss) (b)	$	126	$	154	$	(145)
Per diluted share:
Income (loss) from continuing operations	$	0.11	$	0.42	$	(0.18)
Net Income (loss)	$	0.11	$	0.42	$	(0.16)
Adjusted income (loss) from continuing operations (b)	$	0.15	$	0.18	$	(0.24)
Adjusted net income (loss) (b)	$	0.15	$	0.18	$	(0.17)
Weighted average diluted shares	855		852		850

(a) The Company sold the Canadian oil sands business which is reflected as discontinued operations in periods prior to and including the second quarter 2017.

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

Supplemental Statistics (Unaudited)	Three Months Ended
	June 30		Mar. 31		June 30
(in millions)	2018		2018		2017
Segment income (loss)
United States E&P	$	123	$	125	$	(107)
International E&P	142		132		59
Segment income (loss)	265		257		(48)
Not allocated to segments	(169)		99		(105)
Loss from continuing operations	96		356		(153)
Discontinued operations (a)	—		—		14
Net income (loss)	$	96	$	356	$	(139)
Exploration expenses
United States E&P	$	64	$	51	$	30
International E&P	1		1		—
Total	$	65	$	52	$	30
Cash flows
Net cash provided by operating activities from continuing operations	$	767	$	649	$	422
Minus: changes in working capital	(82)		(58)		(49)
Total net cash provided from continuing operations before changes in working capital (b)	$	849	$	707	$	471
Net cash provided by operating activities from discontinued operations (a)	—		—		46

Cash additions to property, plant and equipment	$	(638)	$	(662)	$	(492)

(a) The Company sold the Canadian oil sands business which is reflected as discontinued operations in periods prior to and including the second quarter 2017.

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

Supplemental Statistics (Unaudited)	Three Months Ended
(in millions)	June 30, 2018
Organic Free Cash Flow
Net cash provided by operating activities from continuing operations	$	767
Development capital expenditures	(608)
Dividends	(43)
Changes in working capital	82
Exploration costs other than well costs	14
EG LNG return of capital & other	43
Organic free cash flow (a)	$	255

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

	Three Months Ended
	June 30	Mar. 31	June 30
(mboed)	2018	2018	2017
Net production
United States E&P	298	284	222
International E&P excluding Libya (a)	121	114	127
Total continuing operations, excluding Libya (a)	419	398	349
Libya (a)	—	28	11
Total continuing operations	419	426	360

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

	Three Months Ended
	June 30	Mar. 31	June 30
(mboed)	2018	2018	2017
Net production
United States E&P	298	284	222
Less: Divestitures (a)	—	(1)	(3)
Divestiture-adjusted United States E&P (a)	298	283	219
Divestiture-adjusted total continuing operations, excluding Libya (a)	419	397	346
Discontinued operations (b)	—	—	29

(a) Divestitures include the sale of certain conventional assets in Oklahoma in September 2017 and Colorado in October 2017. These production volumes have been removed from all historical periods shown in arriving at divestiture-adjusted United States E&P net production and divestiture-adjusted total continuing operations, excluding Libya. The Company closed on the sale of its Libya subsidiary in the first quarter 2018.

(b) The Company sold the Canadian oil sands business which is reflected as discontinued operations in periods prior to and including the second quarter 2017.

Supplemental Statistics (Unaudited)	Three Months Ended
	June 30	Mar. 31	June 30
	2018	2018	2017
United States E&P - net sales volumes
Crude oil and condensate (mbbld)	168	164	125
Eagle Ford	63	63	59
Bakken	69	61	39
Oklahoma	18	20	14
Northern Delaware	11	10	2
Other United States (a)	7	10	11
Natural gas liquids (mbbld)	57	50	40
Eagle Ford	22	21	20
Bakken	7	7	6
Oklahoma	24	18	12
Northern Delaware	3	3	1
Other United States (a)	1	1	1
Natural gas (mmcfd)	435	420	341
Eagle Ford	127	122	127
Bakken	35	35	25
Oklahoma	230	216	138
Northern Delaware	18	17	7
Other United States (a)	25	30	44
Total United States E&P (mboed)	298	284	222
International E&P - net sales volumes
Crude oil and condensate (mbbld)	32	63	43
Equatorial Guinea	18	15	18
United Kingdom	10	15	13
Libya (b)	—	28	11
Other International	4	5	1
Natural gas liquids (mbbld)	12	11	12
Equatorial Guinea	11	11	12
United Kingdom	1	—	—
Natural gas (mmcfd)	461	437	478
Equatorial Guinea	443	403	452
United Kingdom (c)	18	12	26
Libya (b)	—	22	—
Total International E&P (mboed)	121	147	135
Total Company continuing operations - net sales volumes (mboed)	419	431	357
Net sales volumes of equity method investees
LNG (mtd)	6,141	5,541	6,243
Methanol (mtd)	1,316	1,195	1,182
Condensate and LPG (boed)	12,689	12,416	11,608

(a) Includes sales volumes from conventional onshore assets sold in the applicable periods. The sale of certain Oklahoma and Colorado assets closed in September 2017 and October 2017.

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

Supplemental Statistics (Unaudited)	Three Months Ended
	June 30		Mar. 31		June 30
	2018		2018		2017
United States E&P - average price realizations (a)
Crude oil and condensate ($ per bbl) (c)	$	66.03	$	62.22	$	45.81
Eagle Ford	68.77		64.37		45.75
Bakken	64.41		60.20		46.20
Oklahoma	66.90		62.70		45.42
Northern Delaware	60.01		60.45		43.38
Other United States (b)	64.42		61.71		45.71
Natural gas liquids ($ per bbl)	$	22.09	$	22.95	$	17.61
Eagle Ford	22.68		22.85		16.63
Bakken	25.52		23.57		15.16
Oklahoma	20.75		22.59		19.63
Northern Delaware	19.10		22.11		17.54
Other United States (b)	25.62		28.66		23.78
Natural gas ($ per mcf) (d)	$	2.18	$	2.59	$	3.05
Eagle Ford	2.82		3.03		3.06
Bakken	2.46		3.25		3.14
Oklahoma	1.84		2.20		3.07
Northern Delaware	1.48		3.09		2.72
Other United States (b)	2.11		2.64		2.92
International E&P - average price realizations
Crude oil and condensate ($ per bbl)	$	66.12	$	66.23	$	47.04
Equatorial Guinea	60.30		51.94		39.73
United Kingdom	77.15		69.95		54.15
Libya (e)	—		73.75		50.94
Other International	64.73		55.29		40.64
Natural gas liquids ($ per bbl)	$	2.91	$	1.83	$	1.77
Equatorial Guinea (f)	0.99		1.00		1.00
United Kingdom	43.20		44.53		32.33
Natural gas ($ per mcf)	$	0.52	$	0.65	$	0.57
Equatorial Guinea (f)	0.24		0.24		0.24
United Kingdom	7.39		7.32		6.27
Libya (e)	—		4.57		—
Benchmark
WTI crude oil (per bbl)	$	67.91	$	62.89	$	48.15
Brent (Europe) crude oil (per bbl)(g)	$	74.50	$	66.81	$	49.67
Henry Hub natural gas (per mmbtu)(h)	$	2.80	$	3.00	$	3.18

(a) Excludes gains or losses on commodity derivative instruments.

(b) Includes sales volumes from conventional onshore assets sold in the applicable periods. The sale of certain Oklahoma and Colorado assets closed in September 2017 and October 2017.

(c) Inclusion of realized gains (losses) on crude oil derivative instruments would have affected average price realizations by $(7.04), $(4.33), and $1.07, for the second and first quarter of 2018, and second quarter of 2017.

(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 July 31, 2018 and the weighted average prices for those contracts:

*Crude Oil*	3Q 2018	4Q 2018	FY 2019	FY 2020
*Three-Way Collars*
Volume (Bbls/day)	95,000	95,000	50,000	—
Weighted average price per Bbl:
Ceiling	$57.65	$57.65	$71.74	—
Floor	$52.11	$52.11	$56.01	—
Sold put	$45.21	$45.21	$48.91	—
*Basis Swaps ^(a)*
Volume (Bbls/day)	10,000	10,000	10,000	15,000
Weighted average price per Bbl	$(0.67)	$(0.67)	$(0.82)	$(0.94)

*Natural Gas*	3Q 2018	4Q 2018
*Three-Way Collars*
Volume (MMBtu/day)	160,000	160,000
Weighted average price per MMBtu:
Ceiling	$3.61	$3.61
Floor	$3.00	$3.00
Sold put	$2.50	$2.50