Marathon Oil Announces $2.4 Billion Development Capital Budget for 2019; Reports Fourth Quarter and Full-Year 2018 Results

2019 Budget Organic Free Cash Flow Positive Above $45/BBL WTI; Returned Over 25% of 2018 Annual Operating Cash Flow to Shareholders

News provided by

Marathon Oil Corporation

Feb 13, 2019, 16:30 ET

HOUSTON, Feb. 13, 2019 /PRNewswire/ -- Marathon Oil Corporation (NYSE:MRO) today announced its 2019 capital expenditure budget in addition to its fourth quarter and full-year 2018 financial results. The 2019 plan and 2018 financial and operating results together reflect the Company's ongoing commitment to its core strategy: corporate returns improvement, sustainable free cash flow generation at conservative oil prices, and the return of capital to shareholders.

2019 Capital Budget Highlights

Total 2019 capital budget of $2.6 billion, down from 2018

Total capital budget includes approx. $2.4 billion of development capital and approx. $200 million of resource play leasing and exploration (REx) spend
Organic free cash flow positive above approx. $45/bbl WTI, post-dividend
Designed to generate meaningful organic free cash flow at $50/bbl WTI, post-dividend

Cumulative two-year (2019-2020) organic free cash flow of over $750 million at flat $50/bbl WTI and over $2.2 billion at flat $60/bbl WTI

Continue to prioritize sustainable free cash flow and return of capital to shareholders
Shareholder return of capital metric incorporated into executive compensation scorecard complementing already well-established corporate cash return on invested capital (CROIC) and cash flow per debt adjusted share (CFPDAS) metrics

Capital efficient U.S. oil growth of 12% in 2019 with annual gross operated wells to sales flat to 2018

Total Company oil growth of 10% in 2019
High value oil growth exceeds BOE growth, an outcome of returns-first capital allocation

More than 95% of $2.4 billion development capital budget allocated to the four U.S. resource plays with approx. 60% to the Eagle Ford and Bakken and approx. 40% to Oklahoma and the Northern Delaware

Continues underlying rate of change improvement in key enterprise financial performance metrics of CROIC and CFPDAS
Development capital includes dedicated funding to organic resource base enhancement initiatives including core extension efforts

REx spend is expected to decline to a more ratable $200 million, supporting progression of Louisiana Austin Chalk and other emerging opportunities with a focus on full-cycle returns

Full-year 2018 Results
Marathon Oil reported full-year 2018 net income of $1,096 million, or $1.29 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 $601 million, or $0.71 per diluted share. Net operating cash flow was $3,234 million, or $3,211 million before changes in working capital.

Full-year 2018 Highlights

Delivered on commitment to capital discipline with no change to initial $2.3 billion development capital budget
Realized 78% annual improvement in CROIC and 65% annual improvement in CFPDAS
Generated more than $865 million of organic free cash flow, post-dividend
Prioritized return of capital to shareholders by paying annual dividend of $169 million and executing $700 million of share repurchases, leaving $800 million of remaining repurchase authorization; over 25% of 2018 net operating cash flow returned to shareholders
Improvement in capital efficiency drove oil production outperformance; total Company oil production growth of 24%, divestiture adjusted, outperformed initial midpoint guidance of 18%; U.S. resource play oil production growth of 32% outperformed initial midpoint guidance of 22.5%
Maintained focus on resource base enhancement and full-cycle returns by advancing successful core extension tests in Eagle Ford and Bakken and progressing REx program; acquired approx. 260,000 net acres at less than $850 per acre in the emerging Louisiana Austin Chalk play
Continued portfolio management with successful sale of Libya and receipt of final payment for the sale of oil sands mining business; disposition proceeds more than fully funded REx and all other resource capture activities, including successful participation in the New Mexico Bureau of Land Management (BLM) lease sale
Drillbit F&D costs of less than $12.50/boe at 125% reserve replacement
Further strengthened balance sheet and financial flexibility by increasing cash and cash equivalents by $900 million to $1.5 billion at year-end

"2018 was a year of differentiated execution for Marathon Oil," said Chairman, President and CEO Lee Tillman. "While many in our industry talked about capital discipline, we delivered. In 2018, we budgeted conservatively and never wavered, getting more for every dollar of capital we invested. We drove significant improvement to our corporate returns and cash flow per debt adjusted share. Through improving capital efficiency we delivered more oil growth, generated $865 million of organic free cash flow post-dividend, and returned most of that cash back to our shareholders via share repurchases. As we turn to 2019 and beyond, we remain committed to this same framework for success. With the foundation of a peer leading balance sheet and the competitive advantages of our multi-basin portfolio, our 2019 capital program will drive improving corporate returns and generate organic free cash flow above $45 WTI, as we continue to prioritize return of cash to our shareholders."

Fourth Quarter 2018 Results
Marathon Oil reported fourth quarter 2018 net income of $390 million, or $0.47 per diluted share. Adjusted net income was $121 million, or $0.15 per diluted share. Net operating cash flow was $855 million, or $787 million before changes in working capital.

Fourth Quarter 2018 Highlights

Generated more than $255 million of organic free cash flow, post-dividend
Development capital spend at $503 million, down 10% sequentially
Total Company production averaged 411,000 net boed; total oil production averaged 206,000 net bopd, up 17% from the year-ago quarter, divestiture adjusted
U.S. resource play production averaged 295,000 net boed; oil production averaged 174,000 net bopd, up 22% from the year-ago quarter
Eagle Ford production averaged 107,000 net boed; 38 wells achieved an average 30-day IP rate of 1,810 boed (72% oil)
Bakken production averaged 94,000 net boed; core extension test in Ajax area of Dunn County meaningfully exceeded expectations with four-well pad achieving an average 30-day IP rate of 2,370 boed (81% oil) at an average completed well cost of approx. $5 million
Oklahoma production averaged 67,000 net boed; transition to multi-well pads continued with another successful SCOOP Woodford infill development that also included a positive Springer delineation test
Northern Delaware production increased to 26,000 net boed; 12 gross Company-operated wells to sales with an average 30-day IP rate of 1,935 boed (49% oil)

U.S.
U.S. production averaged 306,000 net barrels of oil equivalent per day (boed) for fourth quarter 2018, including oil production of 180,000 net barrels of oil per day (bopd). Oil production was up 4 percent compared to the prior quarter and up 22 percent from the year-ago quarter on a divestiture-adjusted basis. Fourth quarter production from the U.S. resource plays was 295,000 net boed, including oil production of 174,000 net bopd. Fourth quarter U.S. unit production costs were $5.31 per barrel of oil equivalent (boe), a sequential reduction of 14 percent.

EAGLE FORD: Marathon Oil's Eagle Ford production averaged 107,000 net boed in the fourth quarter, up 2 percent from the year-ago quarter. The Company brought 38 gross Company-operated wells to sales in the quarter with an average 30-day initial production (IP) rate of 1,810 boed (72% oil).

BAKKEN: In fourth quarter 2018, Marathon Oil's Bakken production averaged 94,000 net boed, up 37 percent from the year-ago quarter. Oil production was up over 40 percent from the year-ago quarter. The Company brought 27 gross Company-operated wells to sales with an average 30-day IP rate of 3,335 boed (76% oil), with activity primarily concentrated in Myrmidon. The Company also conducted a successful core extension test in the Ajax area of Dunn County, as the four-well Gloria pad achieved an average 30-day IP rate of 2,370 boed (81% oil) at an average completed well cost of approx. $5 million.

OKLAHOMA: Marathon Oil's Oklahoma production averaged 67,000 net boed during fourth quarter 2018, up 4 percent from the year-ago quarter, with only 12 gross Company-operated wells brought to sales. In the SCOOP Woodford, seven infill wells on the 3R pad (eight wells per section spacing) achieved an average 30-day IP rate of 2,600 boed (69% liquids). On the same pad, Marathon Oil also brought online a Springer delineation well that achieved a 30-day IP rate of 1,825 boed (81% oil).

NORTHERN DELAWARE: Marathon Oil's Northern Delaware production increased to an average of 26,000 net boed in fourth quarter 2018, up 138 percent from the year-ago quarter. The Company brought 12 gross Company-operated wells to sales in the Malaga and Red Hills areas with an average 30-day IP rate of 1,935 boed (49% oil), or 360 boed per 1,000 foot lateral. Fourth quarter activity was primarily focused on delineating the Company's acreage position, including Lower Wolfcamp spacing tests in Malaga. During the fourth quarter, the Company executed a comprehensive water management agreement covering the entire Red Hills prospect area, complementing a previously announced agreement in Eddy County.

RESOURCE CAPTURE: Outside of the development capital program, fourth quarter REx capital spending totaled $75 million, consistent with guidance, and bringing full-year 2018 REx spending to $369 million. In addition to REx, full-year 2018 resource capture also included the previously announced $105 million bolt-on acquisition in New Mexico through the BLM lease sale. Total 2018 resource capture spend of $474 million was more than fully funded through divestiture proceeds received in first quarter 2018.

International
International production averaged 105,000 net boed for fourth quarter 2018, down 13 percent compared to the year-ago quarter on a divestiture-adjusted basis. The decrease reflects unscheduled downtime at the non-operated Foinaven complex as well as natural decline and planned maintenance activities in E.G. Fourth quarter 2018 International unit production costs averaged $5.40 per boe.

Production Guidance
For full year 2019, the Company forecasts total oil production growth of 10 percent, with U.S. oil growth of 12 percent, both at the midpoint of guidance and on a divestiture adjusted basis. Oil growth is expected to outpace boe production growth, consistent with a focus on corporate returns. For first quarter 2019, the Company forecasts total oil production of 195 - 215 bopd, with U.S. oil production of 175 - 185 bopd. The first quarter 2019 U.S. production guidance range accounts for extreme weather conditions experienced early in the quarter. The first quarter 2019 International production guidance range reflects a planned triennial shutdown in E.G. to conduct turnaround activity, consistent with prior disclosure. For more specific detail regarding 2019 production guidance, please refer to the guidance tables included within this release.

Corporate
The Company has executed $700 million of share repurchases, returning additional capital to shareholders beyond the $169 million annual dividend. Share repurchases were more than fully funded by organic free cash flow of over $865 million post-dividend.

Total liquidity as of Dec. 31 was approximately $4.9 billion, which consisted of $1.5 billion in cash and cash equivalents and an undrawn revolving credit facility of $3.4 billion which was extended by one year to 2022.

The adjustments to net income for fourth quarter 2018 totaled $256 million before tax, primarily due to the income impact associated with unrealized gains on derivative instruments, partially offset by a write off related to historical International exploration expenses and associated well costs.

For 2019, the Company's open crude hedge positions (as of Feb 12) include an average of 60,000 bopd at a weighted average floor price of $56.67 and a weighted average ceiling price of $73.18, hedged through three-way collars.

Reserves
During 2018, Marathon Oil added proved reserves of 186 million boe for a reserve replacement ratio of 125 percent excluding dispositions, at a drillbit finding and development (F&D) cost of $12.41. Virtually all of the additions were in the U.S. Net proved reserves were approximately 1.28 billion boe at year-end 2018, down from year-end 2017 primarily due to the disposition of Libya.

A slide deck and Quarterly Investor Packet will be posted to the Company's website following this release today, Feb. 13. On Thursday, Feb. 14, 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).
Free cash flow - Operating cash flow, less capital expenditure, less dividends, plus other.
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, 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 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, rates of change for CROIC and CFPDAS, 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 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						Year Ended
	Dec. 31		Sept. 30		Dec. 31		Dec. 31		Dec. 31
(In millions, except per share data)	2018		2018		2017		2018		2017
Revenues and other income:
Revenues from contracts with customers	$	1,380	$	1,538	$	1,336	$	5,902	$	4,247
Net gain (loss) on commodity derivatives	310		(70)		(151)		(14)		(36)
Marketing revenues	—		—		45		—		162
Income from equity method investments	64		64		73		225		256
Net gain (loss) on disposal of assets	(4)		16		32		319		58
Other income	15		119		47		150		78
Total revenues and other income	1,765		1,667		1,382		6,582		4,765
Costs and expenses:
Production	205		215		188		842		716
Marketing, including purchases from related parties	—		—		47		—		168
Shipping, handling and other operating	167		152		122		575		431
Exploration	116		56		57		289		409
Depreciation, depletion and amortization	613		626		583		2,441		2,372
Impairments	25		8		24		75		229
Taxes other than income	84		86		55		299		183
General and administrative	88		101		95		394		371
Total costs and expenses	1,298		1,244		1,171		4,915		4,879
Income (loss) from operations	467		423		211		1,667		(114)
Net interest and other	(58)		(58)		(71)		(226)		(270)
Other net periodic benefit costs	(3)		(8)		(3)		(14)		(19)
Loss on early extinguishment of debt	—		—		(5)		—		(51)
Income (loss) from continuing operations before income taxes	406		357		132		1,427		(454)
Provision (benefit) for income taxes	16		103		160		331		376
Income (loss) from continuing operations	390		254		(28)		1,096		(830)
Income (loss) from discontinued operations (a)	—		—		—		—		(4,893)
Net income (loss)	$	390	$	254	$	(28)	$	1,096	$	(5,723)

Adjusted Net Income (Loss)
Income (loss) from continuing operations	390		254		(28)		1,096		(830)
Adjustments for special items from continuing operations (pre-tax):
Net (gain) loss on disposal of assets	4		(16)		(32)		(319)		(57)
Proved property impairments	25		8		24		75		225
Exploratory dry well costs, unproved property impairments and other	40		—		—		40		250
Pension settlement	5		10		7		21		32
Unrealized (gain) loss on derivative instruments	(336)		(19)		145		(267)		81
Reduction of U.K. ARO estimated costs	—		(113)		(53)		(121)		(53)
Other	6		—		5		6		(2)
Provision (benefit) for income taxes related to special items from continuing operations	(13)		76		(12)		70		(13)
Valuation allowance	—		—		—		—		41
Adjustments for special items	(269)		(54)		84		(495)		504
Adjusted income (loss) from continuing operations (a)	$	121	$	200	$	56	$	601	$	(326)
Income (loss) from discontinued operations (b)	—		—		—		—		(4,893)
Adjustments for special items from discontinued operations (pre-tax):
Canadian oil sands business impairment (b)	—		—		—		—		6,636
Net (gain) loss on disposition (b)	—		—		—		—		43
Provision (benefit) for income taxes related to special items from discontinued operations (b)	—		—		—		—		(1,674)
Adjusted net income (loss) (a)	$	121	$	200	$	56	$	601	$	(214)
Per diluted share:
Income (loss) from continuing operations	$	0.47	$	0.30	$	(0.03)	$	1.30	$	(0.97)
Net income (loss)	$	0.47	$	0.30	$	(0.03)	$	1.30	$	(6.73)
Adjusted income (loss) from continuing operations (a)	$	0.15	$	0.24	$	0.07	$	0.71	$	(0.38)
Adjusted net income (loss) (a)	$	0.15	$	0.24	$	0.07	$	0.71	$	(0.25)
Weighted average diluted shares	829		849		850		847		850

(a)	The Company closed on its sale of the Canadian oil sands business in the second quarter of 2017 which is reflected as discontinued operations for the year ended December 31, 2017.
(b)	Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended						Year Ended
	Dec. 31		Sept. 30		Dec. 31		Dec. 31		Dec. 31
(In millions)	2018		2018		2017		2018		2017
Segment income (loss)
United States	$	159	$	201	$	76	$	608	$	(148)
International	83		116		118		473		374
Segment income (loss)	242		317		194		1,081		226
Not allocated to segments	148		(63)		(222)		15		(1,056)
Income (loss) from continuing operations	390		254		(28)		1,096		(830)
Income (loss) from discontinued operations (a)	—		—		—		—		(4,893)
Net income (loss)	$	390	$	254	$	(28)	$	1,096	$	(5,723)
Exploration expenses
United States	$	76	$	55	$	57	$	246	$	154
International	—		1		—		3		5
Segment exploration expenses	76		56		57		249		159
Not allocated to segments	40		—		—		40		250
Total	$	116	$	56	$	57	$	289	$	409
Cash flows
Net cash provided by operating activities from continuing operations	$	855	$	963	$	501	$	3,234	$	1,988
Minus: changes in working capital	68		103		(2)		23		(26)
Minus: U.K. tax payment	—		—		(108)		—		(108)
Total net cash provided from continuing operations before changes in working capital and the U.K. tax payment (b)	$	787	$	860	$	611	$	3,211	$	2,122
Net cash provided by operating activities from discontinued operations (a)	$	—	$	—	$	—	$	—	$	141

Cash additions to property, plant and equipment	$	(684)	$	(769)	$	(669)	$	(2,753)	$	(1,974)

(a)	The Company closed on its sale of the Canadian oil sands business in the second quarter of 2017 which is reflected as discontinued operations for the year ended December 31, 2017.
(b)	Non-GAAP financial measure. See "Non-GAAP Measures" above for further discussion.

Supplemental Statistics (Unaudited)	Three Months Ended		Year Ended
(In millions)	Dec. 31, 2018		Dec. 31, 2018
Organic Free Cash Flow
Net cash provided by operating activities	$	855	$	3,234
Minus: changes in working capital	68		23
Minus: exploration costs other than well costs	(5)		(34)
Development capital expenditures	(503)		(2,286)
Dividends	(41)		(169)
EG LNG return of capital and other	9		78
Organic free cash flow (a)	$	257	$	868

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

Supplemental Statistics (Unaudited)	Three Months Ended			Year Ended
	Dec. 31	Sept. 30	Dec. 31	Dec. 31	Dec. 31
(mboed)	2018	2018	2017	2018	2017
Net production
United States	306	304	262	298	235
International, excluding Libya (a)	105	115	121	114	123
Total net production from continuing operations, excluding Libya (a)	411	419	383	412	358
Libya (a)	—	—	33	7	19
Total net production from continuing operations	411	419	416	419	377

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

Supplemental Statistics (Unaudited)	Three Months Ended			Year Ended
	Dec. 31	Sept. 30	Dec. 31	Dec. 31	Dec. 31
(mboed)	2018	2018	2017	2018	2017
Net production
United States	306	304	262	298	235
Less: Divestitures (a)	—	1	4	3	8
Total divestiture-adjusted United States	306	303	258	295	227

International	105	115	154	121	142
Less: Divestitures (b)	—	1	35	8	20
Total divestiture-adjusted International	105	114	119	113	122

Total net production divestiture-adjusted (a)(b)	411	417	377	408	349
Discontinued operations (c)	—	—	—	—	18

(a)	The Company closed on the sale of certain United States 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 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 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 net production.
(c)	The Company closed on its sale of the Canadian oil sands business in the second quarter of 2017 which is reflected as discontinued operations for the year ended December 31, 2017.

Supplemental Statistics (Unaudited)	Three Months Ended			Year Ended
	Dec. 31	Sept. 30	Dec. 31	Dec. 31	Dec. 31
	2018	2018	2017	2018	2017
United States - net sales volumes
Crude oil and condensate (mbbld)	180	173	150	171	133
Eagle Ford	62	66	61	63	59
Bakken	82	72	58	71	46
Oklahoma	16	18	16	18	15
Northern Delaware	14	12	8	12	4
Other United States (a)	6	5	7	7	9
Natural gas liquids (mbbld)	55	58	49	55	43
Eagle Ford	24	26	23	23	21
Bakken	6	6	6	7	6
Oklahoma	19	21	18	20	14
Northern Delaware	5	4	1	4	1
Other United States (a)	1	1	1	1	1
Natural gas (mmcfd)	422	433	376	429	348
Eagle Ford	127	137	127	129	125
Bakken	35	36	26	35	25
Oklahoma	192	208	180	213	149
Northern Delaware	42	30	14	26	9
Other United States (a)	26	22	29	26	40
Total United States (mboed)	305	303	262	298	234
International - net sales volumes
Crude oil and condensate (mbbld)	29	27	58	39	52
Equatorial Guinea	16	18	20	17	21
United Kingdom	10	6	5	11	10
Libya (b)	—	—	29	7	19
Other International	3	3	4	4	2
Natural gas liquids (mbbld)	10	11	13	11	12
Equatorial Guinea	10	11	12	11	11
United Kingdom	—	—	1	—	1
Natural gas (mmcfd)	411	441	493	435	485
Equatorial Guinea	400	426	464	416	459
United Kingdom (c)	11	15	15	14	22
Libya (b)	—	—	14	5	4
Total International (mboed)	108	112	153	122	145
Total Company - net sales volumes (mboed)	413	415	415	420	379
Net sales volumes of equity method investees
LNG (mtd)	5,384	6,152	6,353	5,805	6,423
Methanol (mtd)	1,119	1,334	1,637	1,241	1,374
Condensate and LPG (boed)	15,071	11,942	14,605	13,034	14,501

(a)	Includes sales volumes from the sale of certain United States 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						Year Ended
	Dec. 31		Sept. 30		Dec. 31		Dec. 31		Dec. 31
	2018		2018		2017		2018		2017
United States - average price realizations (a)
Crude oil and condensate ($ per bbl) (b)	$	56.01	$	68.51	$	55.46	$	63.11	$	49.35
Eagle Ford	63.27		72.00		57.82		67.19		49.93
Bakken	51.11		67.26		54.42		60.39		49.28
Oklahoma	58.42		70.14		53.90		64.63		48.79
Northern Delaware	48.04		55.01		53.74		55.23		48.84
Other United States (c)	60.41		66.67		48.87		63.11		46.98
Natural gas liquids ($ per bbl)	$	24.71	$	28.07	$	23.60	$	24.54	$	20.55
Eagle Ford	21.46		28.62		22.54		24.08		19.32
Bakken	19.01		31.92		24.09		24.98		18.38
Oklahoma	29.55		25.29		24.16		24.38		22.74
Northern Delaware	28.99		31.44		26.79		26.30		24.04
Other United States (c)	26.68		34.71		30.06		28.63		24.61
Natural gas ($ per mcf) (d)	$	3.27	$	2.55	$	2.65	$	2.65	$	2.84
Eagle Ford	3.69		2.84		2.82		3.09		2.89
Bakken	3.46		2.64		2.82		2.95		2.80
Oklahoma	3.22		2.40		2.54		2.38		2.82
Northern Delaware	1.80		2.24		2.37		2.08		2.70
Other United States (c)	3.65		2.48		2.56		2.73		2.82
International - average price realizations
Crude oil and condensate ($ per bbl)	$	58.25	$	64.08	$	61.32	$	64.25	$	53.05
Equatorial Guinea	46.35		61.23		52.92		55.28		46.02
United Kingdom	78.49		73.28		61.94		74.34		54.51
Libya (e)	—		—		68.31		73.75		60.72
Other International	52.52		62.30		48.89		58.89		44.73
Natural gas liquids ($ per bbl)	$	2.25	$	2.04	$	4.66	$	2.27	$	3.15
Equatorial Guinea (f)	1.00		1.00		1.00		1.00		1.00
United Kingdom	33.44		50.37		45.71		41.66		39.65
Natural gas ($ per mcf)	$	0.49	$	0.50	$	0.59	$	0.54	$	0.55
Equatorial Guinea (f)	0.24		0.24		0.24		0.24		0.24
United Kingdom	9.13		8.60		7.20		8.03		6.28
Libya (e)	—		—		5.03		4.57		5.03
Benchmark
WTI crude oil (per bbl)	$	59.34	$	69.43	$	55.30	$	64.90	$	50.85
Brent (Europe) crude oil (per bbl)(g)	$	67.71	$	75.22	$	61.53	$	71.06	$	54.25
Henry Hub natural gas (per mmbtu)(h)	$	3.64	$	2.90	$	2.93	$	3.09	$	3.11

(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 $(1.50), $(5.70), $(0.76), $(4.60) and $0.75 for the fourth and third quarters of 2018, the fourth quarter of 2017, and the years 2018 and 2017, respectively.
(c)	Includes sales volumes from the sale of certain United States 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 segment.
(g)	Average of monthly prices obtained from Energy Information Administration website.
(h)	Settlement date average per mmbtu.

Full-Year 2019 Production Guidance	Oil Production (mbbld)			Equivalent Production (mboed)
Full-Year 2019 Production Guidance	2019		2018	2019		2018
	Low	High	Divestiture-Adjusted (a)	Low	High	Divestiture-Adjusted (a)
Net production
United States	185	195	169	320	330	295
International	20	30	27	90	100	110
Total net production	205	225	196	410	430	405

(a)	Divestiture-adjusted also removes volumes associated with Atrush which is treated as held for sale.

Q1 2019 Production Guidance	Oil Production (mbbld)				Equivalent Production (mboed)
Q1 2019 Production Guidance	Q1 2019		Q4 2018	Q1 2018	Q1 2019		Q4 2018	Q1 2018
	Low	High	Divestiture-Adjusted (a)	Divestiture-Adjusted (a)	Low	High	Divestiture-Adjusted (a)	Divestiture-Adjusted (a)
Net production
United States	175	185	180	160	295	305	306	278
International	20	30	23	30	85	95	102	110
Total net production	195	215	203	190	380	400	408	388

(a)	Divestiture-adjusted also removes volumes associated with Atrush which is treated as held for sale.


Estimated Net Proved Reserves from Continuing Operations (mmboe)	U.S	Int'l	Total
As of December 31, 2017	1,020	429	1,449
Additions	100	2	102
Revisions	71	13	84
Acquisitions	—	—	—
Dispositions	(4)	(197)	(201)
Production	(109)	(44)	(153)
As of December 31, 2018	1,078	203	1,281

Organic Changes in Reserves (excluding dispositions) (mmboe)			186
Production (excluding dispositions) (mmboe) (a)			149
Organic Reserve Replacement Ratio (excluding dispositions)			125		%

Finding Costs ($ in millions, except as indicated)			2018
Property Acquisition Costs - Proved			$	222
Property Acquisition Costs - Unproved			144
Exploration			921
Development			1,204
Total Company - Costs Incurred			$	2,491

Cost Incurred			$	2,491
Organic Changes in Reserves (excluding dispositions) (mmboe)			186
Finding and Development Costs per BOE			$	13.39

Costs Incurred			$	2,491
Property Acquisition Costs (Proved and Unproved)			(366)
Capitalized Asset Retirement Costs			183
Organic Finding and Development Costs			$	2,308
Organic Changes in Reserves (excluding dispositions) (mmboe)			186
Organic Finding and Development Costs per BOE			$	12.41

(a)	Excludes approximately 4 mmboe related to certain dispositions, primarily the sale of our Libya subsidiary in the first quarter 2018.

The following tables set forth outstanding derivative contracts as of February 12, 2019 and the weighted average prices for those contracts:

	2019				2020
*Crude Oil*	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Full Year
*Three-Way Collars*
Volume (Bbls/day)	70,000	70,000	50,000	50,000	—
Weighted average price per Bbl:
Ceiling	$71.21	$71.21	$75.88	$75.88	—
Floor	$55.86	$55.86	$57.80	$57.80	—
Sold put	$48.71	$48.71	$50.80	$50.80	—
*Basis Swaps ^(a)(b)*
Volume (Bbls/day)	10,000	11,000	16,000	16,000	15,000
Weighted average price per Bbl	$(0.82)	$(1.06)	$(1.53)	$(1.53)	$(0.94)
*NYMEX Roll Basis Swaps*
Volume (Bbls/day)	60,000	60,000	60,000	60,000	—
Weighted average price per Bbl	$0.38	$0.38	$0.38	$0.38	—
*Natural Gas*
*Three-Way Collars*
Volume (MMBtu/day)	200,000	—	—	—	—
Weighted average price per MMBtu:
Ceiling	$5.25	—	—	—	—
Floor	$3.43	—	—	—	—
Sold put	$2.88	—	—	—	—

^(a)	The basis differential price is between WTI Midland and WTI Cushing.
^(b)	Between January 1, 2019 and February 12, 2019, the Company entered into 5,000 Bbls/day of Midland basis swaps for July - December 2019 with an average price of $(2.55) and 1,000 Bbls/day of Clearbrook basis swaps for March - December 2019 with an average price of $(3.50).