May 4, 2016

Marathon Oil Reports First Quarter 2016 Results

Strengthened Balance Sheet Provides Flexibility

HOUSTON, May 04, 2016 (GLOBE NEWSWIRE) -- Marathon Oil Corporation (NYSE:MRO) today reported a first quarter 2016 adjusted net loss of $317 million, or $0.43 per diluted share, excluding the impact of certain items not typically represented in analysts' earnings estimates and that would otherwise affect comparability of results. The reported net loss was $407 million, or $0.56 per diluted share.

Highlights

  • First quarter total Company net production averaged 388,000 net boed at the upper end of guidance; U.S. resource play production averaged 204,000 net boed
  • Reduced North America E&P production costs to $6.17 per boe, or 22% below year-ago quarter
  • New Eagle Ford high-GOR oil wells with tighter stage spacing continue to perform approximately 20% above offset wells; high-GOR oil wells represent approximately 60% of Eagle Ford future well inventory
  • Announced $950 million in sales of non-core assets in April, bringing total to approximately $1.3 billion since August 2015, exceeding high end of targeted range
  • Quarter-end liquidity of $5.4 billion comprised of $2.1 billion in cash and undrawn $3.3 billion revolving credit facility

"Since the beginning of the year, we've made significant additional progress strengthening our balance sheet. This provides us substantial flexibility in this period of market uncertainty and prepares us to respond to more constructive and sustainable pricing," said Marathon Oil President and CEO Lee Tillman. "With the backdrop of crude and condensate realizations falling more than 20 percent in the first quarter, we remained focused on lowering costs, reducing our capital program consistent with our plan, and delivering production at the upper end of guidance. Additionally, we maintained our commitment to portfolio management with the recently announced $950 million of non-core asset sale transactions, exceeding our target for 2016. With these actions, we're on track to achieve our objective of living within our means in 2016."


North America E&P
North America Exploration and Production (E&P) production available for sale averaged 239,000 net barrels of oil equivalent per day (boed) for first quarter 2016. On a divestiture-adjusted basis, it was down 5 percent from the prior quarter and down 10 percent from the year-ago period due to reduced drilling and completion activities. First quarter North America production costs were 18 percent lower than the previous quarter. On a per barrel basis, unit production costs were $6.17 per barrel of oil equivalent (boe), 11 percent lower than fourth quarter 2015 and down 22 percent from the year-ago period.

EAGLE FORD: In first quarter 2016, Marathon Oil's production in the Eagle Ford averaged 120,000 net boed, compared to 147,000 net boed in the year-ago quarter and 128,000 net boed in the prior quarter. The production decreases were principally due to decreased drilling and completion activity resulting in fewer wells brought to sales. During first quarter 2016, 50 gross Company operated (32 net) wells to sales were brought online, of which 23 were lower Eagle Ford, 19 upper Eagle Ford and eight Austin Chalk, compared to 76 gross (44 net) wells to sales in the previous quarter. Fifteen of the first quarter wells brought to sales were high-GOR oil at reduced 200-foot stage spacing. These wells are performing approximately 20 percent above offset wells with 250-foot stage spacing on average, and results are consistent with a group of 16 wells brought to sales in 2015. High-GOR oil wells comprise more than half of the Company's 2016 Eagle Ford program, and all will be completed at 200-foot, or tighter, stage spacing. First quarter completed well costs were $4.3 million, down approximately 35 percent from the year-ago quarter. Additional drilling efficiencies were captured as first quarter wells were drilled at an average rate of 2,300 feet per day and an average spud-to-total depth of eight days while achieving geo-steering within zone at a 97 percent rate. The top-performing Eagle Ford rigs drilled four wells in excess of 3,300 feet per day.

OKLAHOMA RESOURCE BASINS: The Company's unconventional Oklahoma production averaged 27,000 net boed during first quarter 2016, compared to 25,000 net boed in the year-ago quarter and 28,000 net boed in the prior quarter. Marathon Oil continued its focus on leasehold protection and delineation, and brought online three gross Company-operated single lateral (SL) wells, of which one was in the SCOOP Woodford, one in the SCOOP Springer and one in the STACK Meramec. The 5,000-foot lateral STACK Meramec well was completed in the volatile oil phase window and had a 30-day initial production (IP) rate of 755 boed with 78 percent liquids. In the SCOOP, the Company tested the updip oil extension in the northeast Springer trend, but encountered mechanical wellbore issues and the well has been plugged back to a shorter lateral length. The Company expects to bring four STACK Meramec extended-reach lateral (XL) wells and three SCOOP Woodford XL wells to sales in the second quarter.

BAKKEN: Marathon Oil averaged 57,000 net boed of production in the Bakken during first quarter 2016, flat to the year-ago quarter and compared to 58,000 net boed in the prior quarter as strong well productivity and high reliability continued supporting the Company's base production. The remaining drilling rig was released and six gross wells were brought to sales in the quarter -- four Middle Bakken and two Three Forks -- as the Company continued its shift to higher intensity completions. Additionally, five wells on the Clark's Creek pad in West Myrmidon have been drilled and are expected online in the second quarter. Bakken production costs have decreased by over 35 percent compared to the year-ago quarter primarily a result of lower water handling and contract labor costs. More than half of produced water is now moved via pipeline.


International E&P
International E&P production available for sale (excluding Libya) averaged 100,000 net boed for first quarter 2016 compared to 119,000 net boed in the year-ago quarter and 123,000 net boed in the previous quarter. The sequential decrease was primarily a result of planned downtime in Equatorial Guinea and repairs at Brae Alpha in the U.K. First quarter production costs (excluding Libya) were 15 percent lower than the previous quarter. On a per barrel basis, unit production costs (excluding Libya) were $5.09 per boe.

EQUATORIAL GUINEA: Production available for sale averaged 84,000 net boed in first quarter 2016 compared to 99,000 net boed in the year-ago quarter and 104,000 net boed in the previous quarter. During the quarter, the Alba compression jacket and topsides were installed, and planned maintenance was completed ahead of schedule and under budget. The compression project remains on schedule for first production mid-year while base production continues to benefit from last year's re-completion and development programs.

U.K.: Production available for sale averaged 16,000 net boed in first quarter 2016, compared to 20,000 net boed in the year-ago quarter and 18,000 net boed in the previous quarter. First quarter 2016 was impacted by repair activities following a process pipe failure in December at the Brae Alpha facilities, partially offset by improved reliability from the outside-operated Foinaven field. Full production from Brae Alpha resumed in late April.


Oil Sands Mining
Oil Sands Mining (OSM) production available for sale for first quarter 2016 averaged 49,000 net barrels per day (bbld) compared to 50,000 net bbld in the prior-year quarter and flat with fourth quarter 2015. In mid-March, planned maintenance activities began ahead of schedule at the expansion upgrader and the Jackpine mine. Despite the impacts associated with the planned maintenance activities, operating expense per synthetic barrel (before royalties) was $28.80, 17 percent below the year-ago quarter as a result of sustainable reductions in mine expenses, reliability and currency effects. Operating expense has been below $30 per synthetic barrel (before royalties) for three consecutive quarters.


Production Guidance
Marathon Oil expects second quarter 2016 North America E&P production available for sale to average 220,000 to 230,000 net boed reflecting declines as a result of reduced capital investment. Second quarter International E&P production available for sale (excluding Libya) is expected to be within a range of 115,000 to 125,000 net boed as the Alba field in Equatorial Guinea returned to normal operations in February and Brae Alpha in the U.K. resumed production in April. Considerable uncertainty remains around the timing of future production and sales levels from Libya, and Marathon Oil continues to exclude Libya volumes from its production forecasts. OSM synthetic crude oil production is expected to range from 40,000 to 45,000 net bbld reflecting continuation of planned maintenance activities in the second quarter. Second quarter OSM guidance does not include any potential impact from the wildfires in the Fort McMurray area. Operations at the Muskeg River and Jackpine mines, which are approximately 45 miles north, have been suspended to support emergency response efforts, but are not currently threatened by fire.


Corporate and Special Items
Net cash provided by operations before changes in working capital was $55 million during first quarter 2016, and net cash provided by operating activities was $74 million. Additions to property, plant and equipment including accruals were $359 million in first quarter 2016, a 36 percent decrease from the previous quarter and down 67 percent from the year-ago quarter. Total liquidity as of March 31 was $5.4 billion, which consists of $2.1 billion in cash and cash equivalents and an undrawn revolving credit facility that was increased to $3.3 billion in the quarter.

Marathon Oil reduced E&P production expenses and total Company adjusted general and administrative expenses by 26 percent in the first quarter 2016 compared to the same quarter in 2015, or 23 percent lower on an unadjusted basis.

In April, the Company announced agreements for the sale of its Wyoming upstream and midstream assets for $870 million, excluding closing adjustments. The effective date is Jan. 1, 2016, and closing is expected mid-year 2016. In separate transactions, the Company signed agreements for the sale of its 10 percent working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado, and certain undeveloped acreage in West Texas for a combined total of approximately $80 million before closing adjustments.

The adjustments to net loss for first quarter 2016 total $90 million ($141 million pre-tax) and consist of: a net loss on the sale of assets of $40 million ($63 million pre-tax); a pension settlement of $30 million ($48 million pre-tax); an unrealized loss on derivatives of $15 million ($23 million pre-tax); and a severance expense of $5 million ($7 million pre-tax) related to previously announced workforce reductions.

The Company's webcast commentary and associated slides related to Marathon Oil's financial and operational review, as well as the Quarterly Investor Packet, will be posted to the Company's website at http://ir.marathonoil.com and to its mobile app as soon as practicable following this release today, May 4. The Company will conduct a question and answer webcast/call on Thursday, May 5, at 8:30 a.m. ET. The associated commentary and answers to questions will include forward-looking information. To listen to the live webcast, visit the Marathon Oil website at http://www.marathonoil.com. The audio replay of the webcast will be posted by May 6.

# # #

Non-GAAP Measures
Management uses certain non-GAAP financial measures, including adjusted net income (loss), net cash provided by operations before changes in working capital, and adjusted general and administrative expenses, to evaluate the Company's financial performance between periods and to compare the Company's performance to certain competitors. Management also uses net cash provided by operations before changes in working capital to demonstrate the Company's ability to internally fund capital expenditures, pay dividends and service debt. These measures should not be considered substitutes for their most directly comparable GAAP financial measures. See the tables below for reconciliations between each non-GAAP financial measure and its most directly comparable GAAP financial measure, including: (i) adjusted net income (loss) reconciled to net income (loss), (ii) net cash provided by operations before changes in working capital reconciled to net cash provided by operating activities, and (iii) adjusted general and administrative expenses reconciled to total company general and administrative expenses.

Forward-looking Statements
This release (and oral statements made regarding the subjects of 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. These are statements, other than statements of historical fact, that give current expectations or forecasts of future events, including, without limitation: the Company's operational and financial strategies, including project plans, drilling plans, cost reductions, drilling efficiencies, financial and operational flexibility, portfolio management, and living within the Company's means; the Company's ability to successfully effect those strategies and the expected timing and results thereof; the Company's ability to complete the non-core asset sales identified in this release, and the expected timing and results thereof; production guidance; the Company's financial and operational outlook, and ability to fulfill that outlook; the expected benefits of the Company's strengthened balance sheet; expectations regarding future economic and market conditions and their effects on the Company; and the Company's financial position, liquidity and capital resources.

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; capital available for exploration and development; well production timing; availability of drilling rigs, materials and labor; 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 terrorism and the governmental or military response thereto; cyber-attacks; changes in safety, health, environmental 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 2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases, available at www.marathonoil.com. The Company undertakes no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.


 Three Months Ended
 Mar. 31Dec. 31Mar. 31
(In millions, except per diluted share data)201620152015
Adjusted net income (loss) (a)$(317)$(323)$(253)
Adjustments for special items (net of taxes):   
Net gain (loss) on dispositions(40)146  
Proved property impairments (20) 
Unproved property impairments (220) 
Goodwill impairment (340) 
Pension settlement(30)(13)(11)
Unrealized gain (loss) on crude oil derivative instruments(15)(5)15 
Reduction in workforce(5)(6)(27)
Other (12) 
  Net income (loss)$(407)$(793)$(276)
Per diluted share:   
    Adjusted net income (loss) (a)$(0.43)$(0.48)$(0.37)
    Net income (loss)$(0.56)$(1.17)$(0.41)
Exploration expenses   
Unproved property impairments$11 $352 $9 
Dry well costs 154 58 
Geological and geophysical 8 3 
Other13 18 20 
  Total exploration expenses$24 $532 $90 
Cash flows   
Net cash provided by operations before changes in working capital (a)$55 $278 $412 
Changes in working capital19 74 (103)
Net cash provided by operating activities$74 $352 $309 
    
Additions to property, plant and equipment$(359)$(561)$(1,102)
Changes in working capital(95)33 (350)
Cash additions to property, plant and equipment$(454)$(528)$(1,452)

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

Consolidated Statements of Income (Unaudited)Three Months Ended
 Mar. 31Dec. 31Mar. 31
(In millions, except per share data)201620152015
Revenues and other income:   
  Sales and other operating revenues, including related party$714 $1,064 $1,280 
  Marketing revenues58 100 204 
  Income from equity method investments14 47 36 
  Net gain (loss) on disposal of assets(60)228 1 
  Other income4 36 11 
Total revenues and other income730 1,475 1,532 
Costs and expenses:   
  Production328 394 444 
  Marketing, including purchases from related parties58 98 205 
  Other operating109 157 107 
  Exploration24 532 90 
  Depreciation, depletion and amortization609 668 821 
  Impairments1 371  
  Taxes other than income48 43 67 
  General and administrative151 126 171 
Total costs and expenses1,328 2,389 1,905 
Income (loss) from operations(598)(914)(373)
  Net interest and other(85)(87)(47)
Income (loss) before income taxes(683)(1,001)(420)
  Benefit for income taxes(276)(208)(144)
Net income (loss)$(407)$(793)$(276)
Per share data   
Net income (loss) per share:   
  Basic$(0.56)$(1.17)$(0.41)
  Diluted$(0.56)$(1.17)$(0.41)
Weighted average shares:   
  Basic730 678 675 
  Diluted730 678 675 


Supplemental Statistics (Unaudited)Three Months Ended
 Mar. 31Dec. 31Mar. 31
(in millions)201620152015
Segment income (loss)   
North America E&P$(195)$(219)$(161)
International E&P4 19 23 
Oil Sands Mining(48)(6)(19)
  Segment income (loss)(239)(206)(157)
Items not allocated to segments, net of income taxes:   
  Corporate and unallocated(78)(117)(96)
  Net gain (loss) on dispositions(40)146  
  Proved property impairments (20) 
  Unproved property impairments (220) 
  Goodwill impairment (340) 
  Pension settlement(30)(13)(11)
  Unrealized gain (loss) on crude oil derivative instruments(15)(5)15 
  Reduction in workforce(5)(6)(27)
  Other (12) 
    Net income (loss)$(407)$(793)$(276)
Capital expenditures (a)   
North America E&P$315 $505 $933 
International E&P32 93 146 
Oil Sands Mining (b)9 (36)21 
Corporate3 (1)2 
    Total$359 $561 $1,102 
Exploration expenses   
North America E&P$18 $214 $35 
International E&P6 16 55 
    Segment exploration expenses24 230 90 
    Not allocated to segments 302  
      Total$24 $532 $90 
Provision (benefit) for income taxes   
Current income taxes$44 $8 $35 
Deferred income taxes(320)(216)(179)
    Total$(276)$(208)$(144)

(a) Capital expenditures include accruals.
(b) Capital expenditures in 2015 include reimbursements earned from the governments of Canada and Alberta related to funds previously expended for Quest CCS capital equipment. Quest CCS was successfully completed and commissioned in fourth quarter 2015.

 Three Months EndedGuidance(a)
 Mar. 31Dec. 31Mar. 31Q2
(mboed)2016201520152016
Net production available for sale    
North America E&P (b)239 260 283 220-230
International E&P excluding Libya (c)100 123 119 115-125
Combined North America & International E&P, excluding Libya (c)339 383 402  
Oil Sands Mining (d)49 49 50 40-45
Total Company excluding Libya388 432 452  
Libya    
Total Company388 432 452  

(a) Guidance excludes the effect of acquisitions or divestitures.
(b)The sale of the Company's East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets closed in August 2015, and the sale of its Gulf of Mexico assets closed in December 2015 and February 2016.
(c) Libya is excluded because of uncertainty around timing of future production and sales levels.
(d) Upgraded bitumen excluding blendstocks.

 Three Months Ended
 Mar. 31Dec. 31Mar. 31
(mboed)201620152015
Net production available for sale   
North America E&P239 260 283 
Less: Divestitures (a)(1)(10)(17)
   Divestiture-adjusted North America E&P238 250 266 

(a) Divestitures include the sale of East Texas, North Louisiana and Wilburton, Oklahoma assets closed in August 2015, and the sale of Gulf of Mexico assets closed in December 2015 and February 2016. These production volumes have been removed from all periods shown in arriving at divestiture-adjusted North America E&P net production available for sale.

Supplemental Statistics (Unaudited)Three Months Ended
 Mar. 31Dec. 31Mar. 31
 201620152015
North America E&P - net sales volumes   
Liquid hydrocarbons (mbbld)186 200 223 
  Bakken53 52 54 
  Eagle Ford95 99 119 
  Oklahoma resource basins12 13 12 
  Other North America (a)26 36 38 
 Crude oil and condensate (mbbld)147 159 184 
  Bakken47 48 51 
  Eagle Ford70 72 92 
  Oklahoma resource basins5 5 5 
  Other North America (a)25 34 36 
 Natural gas liquids (mbbld)39 41 39 
  Bakken6 4 3 
  Eagle Ford25 27 27 
  Oklahoma resource basins7 8 7 
  Other North America (a)1 2 2 
 Natural gas (mmcfd)315 345 359 
  Bakken25 27 20 
  Eagle Ford154 166 169 
  Oklahoma resource basins89 89 78 
  Other North America (a)47 63 92 
 Total North America E&P (mboed)239 258 283 
International E&P - net sales volumes   
Liquid hydrocarbons (mbbld)32 43 41 
  Equatorial Guinea25 29 28 
  United Kingdom7 14 13 
 Crude oil and condensate (mbbld)23 32 31 
  Equatorial Guinea16 18 18 
  United Kingdom7 14 13 
 Natural gas liquids (mbbld)9 11 10 
  Equatorial Guinea9 11 10 
 Natural gas (mmcfd)382 467 451 
  Equatorial Guinea351 438 418 
  United Kingdom (b)31 29 33 
 Total International E&P (mboed)96 121 116 
Oil Sands Mining - net sales volumes   
Synthetic crude oil (mbbld) (c)59 59 60 
    
Total Company - net sales volumes (mboed)394 438 459 
Net sales volumes of equity method investees   
  LNG (mtd)4,322 6,569 6,275 
  Methanol (mtd)1,280 1,064 884 
  Condensate and LPG (boed)10,208 13,580 13,223 

(a) Includes Gulf of Mexico and other conventional onshore U.S. production. The sale of the Company's Gulf of Mexico assets closed in December 2015 and February 2016.
(b) Includes natural gas acquired for injection and subsequent resale of 5 mmcfd, 8 mmcfd, and 10 mmcfd in the first quarter of 2016, and fourth and first quarters of 2015, respectively.
(c) Includes blendstocks.

Supplemental Statistics (Unaudited)Three Months Ended
 Mar. 31Dec. 31Mar. 31
 201620152015
North America E&P - average price realizations (a)   
Liquid hydrocarbons ($ per bbl)$24.00 $32.47 $36.92 
  Bakken26.00 36.03 37.78 
  Eagle Ford23.02 31.34 36.30 
  Oklahoma resource basins19.41 22.66 28.25 
  Other North America (b)25.51 33.98 40.23 
 Crude oil and condensate ($ per bbl) (c)$28.21 $37.71 $41.75 
  Bakken28.78 38.81 39.92 
  Eagle Ford28.65 38.27 42.72 
  Oklahoma resource basins29.74 38.29 45.57 
  Other North America (b)25.66 34.79 41.39 
 Natural gas liquids ($ per bbl)$8.12 $12.53 $14.43 
  Bakken3.47 5.75 N.M.
  Eagle Ford7.05 12.65 13.73 
  Oklahoma resource basins11.86 12.80 17.04 
  Other North America (b)23.47 22.78 26.38 
 Natural gas ($ per mcf)$2.02 $2.12 $3.01 
  Bakken2.09 1.62 2.93 
  Eagle Ford1.98 2.15 2.88 
  Oklahoma resource basins2.03 2.14 2.61 
  Other North America (b)2.10 2.22 3.59 
International E&P - average price realizations   
Liquid hydrocarbons ($ per bbl)$22.66 $29.18 $37.31 
  Equatorial Guinea20.43 22.82 27.85 
  United Kingdom30.20 41.85 55.81 
 Crude oil and condensate ($ per bbl)$30.95 $38.43 $48.87 
  Equatorial Guinea30.93 35.42 42.55 
  United Kingdom30.72 42.17 57.19 
 Natural gas liquids ($ per bbl)$2.20 $2.08 $3.46 
  Equatorial Guinea (d)1.00 1.00 1.00 
  United Kingdom23.56 31.01 33.64 
 Natural gas ($ per mcf)$0.60 $0.58 $0.78 
  Equatorial Guinea (d)0.24 0.24 0.24 
  United Kingdom4.61 5.73 7.68 
Oil Sands Mining - average price realizations   
Synthetic crude oil ($ per bbl)$26.41 $34.65 $40.37 
    
Benchmark   
  WTI crude oil (per bbl)$33.63 $42.16 $48.58 
  Brent (Europe) crude oil (per bbl)(e)$33.70 $43.56 $53.92 
  Henry Hub natural gas (per mmbtu)(f)$2.09 $2.27 $2.98 
  WCS crude oil (per bbl)(g)$19.21 $27.69 $33.90 

(a) Excludes gains or losses on derivative instruments.
(b) Includes Gulf of Mexico and other conventional onshore U.S. production. The sale of the Company's Gulf of Mexico assets closed in December 2015 and February 2016.
(c) Inclusion of realized gains on crude oil derivative instruments would have increased average price realizations by $1.64, $3.03, and $0.21 for first quarter of 2016 and fourth and first quarters of 2015.
(d) 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.
(e) Average of monthly prices obtained from Energy Information Administration ("EIA") website.
(f) Settlement date average per mmbtu.
(g) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
N.M. -- not material

 Three Months Ended
 Mar. 31Dec. 31Mar. 31
(In millions)201620152015
Production expenses   
North America E&P$134 $164 $202 
International E&P53 63 67 
    Total$187 $227 $269 
    
Total Company general and administrative expenses$151 $126 $171 
Adjustments for special items:   
  Pension settlement(48)(20)(17)
  Reduction in workforce(7)(8)(43)
    Adjusted general and administrative expenses (a)$96 $98 $111 
E&P production expenses and adjusted general and administrative expenses (a)$283 $325 $380 

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

Media Relations Contacts:
Lee Warren: 713-296-4103
Lisa Singhania: 713-296-4101

Investor Relations Contacts:
Chris Phillips: 713-296-3213
Zach Dailey: 713-296-4140


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