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MRO > SEC Filings for MRO > Form 10-Q on 7-May-2014All Recent SEC Filings

Show all filings for MARATHON OIL CORP

Form 10-Q for MARATHON OIL CORP


7-May-2014

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
We are an international energy company based in Houston, Texas, with activities in North America, Europe, Africa and Asia. We have three reportable operating segments. Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
North America E&P - explores for, produces and markets liquid hydrocarbons and natural gas in North America;

International E&P - explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea ("E.G."); and

Oil Sands Mining - mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.

Certain sections of this Quarterly Report on Form 10-Q, including Management's Discussion and Analysis of Financial Condition and Results of Operations, contain forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as "anticipates," "believes," "estimates," "expects," "targets," "plans," "projects," "could," "may," "should," "would" or similar words indicating that future outcomes are uncertain. In accordance with "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2013 Annual Report on Form 10-K. We assume no duty to update these statements as to any future date.
Key Operating and Financial Activities
In the first quarter of 2014, notable activities were:
Increased net income per diluted share to $1.65, which includes $0.83 per diluted share related to the after-tax gain on the sale of our Angola assets, an increase of over 200 percent from the same quarter of last year

Increased income from continuing operations per diluted share to $0.77, up 43 percent from the same quarter of last year

Three high-quality U.S. resource plays averaged net production of 154 thousand barrels of oil equivalent per day ("mboed"), up 26 percent from the first quarter of 2013

            Eagle Ford downspacing results continued to consistently outperform
             modeled type curves


            Austin Chalk and Eagle Ford co-development continuing on plan with
             completion of first 2014 Austin Chalk well at 30-day initial
             production ("IP") rate of 1,600 barrels of oil equivalent per day
             ("boed")


            Bakken and Three Forks co-development progressing with high density
             pilots delivering strong results; testing eight wells per 1,280-acre
             drilling spacing unit


            Bakken recompletions program delivered five wells with initial
             24-hour and 30-day IP rates exceeding expectations


            South Central Oklahoma Oil Province ("SCOOP") extended-reach (XL)
             wells delivering strong results with two wells at 30-day IP rates of
             up to 1,550 boed

Recorded 97 percent average operational availability for operated assets

Marketing of North Sea businesses on schedule; bids due in second quarter

Closed on sales of Angola Blocks 31 and 32 for aggregate cash proceeds of approximately $2 billion, resulting in after-tax gain of $576 million

Completed second phase of $1 billion share repurchase; initiated additional $500 million share repurchase

Significant second quarter activity through May 7, 2014 includes:
Substantially completed additional $500 million share repurchase


Overview and Outlook
Our net sales volumes from continuing operations for the first quarter of 2014 averaged 457 mboed compared to 514 mboed for the first quarter of 2013. Excluding Libya, where we had no oil liftings in the first quarter of 2014 as a result of on-going third-party labor strikes at the Es Sider oil terminal, our net sales volumes from continuing operations for the first quarter of 2014 averaged 457 mboed compared to 476 mboed for the first quarter of 2013. See Supplemental Statistics for a tabular presentation of net sales volumes by product and location for each period.
North America E&P
Production
Net liquid hydrocarbon and natural gas sales volumes averaged 213 mboed in the first quarter of 2014 compared to 198 mboed in the first quarter of 2013, for an increase of approximately 8 percent. Net liquid hydrocarbon sales volumes increased 22 thousand barrels per day ("mbbld") for the first quarter of 2014, primarily reflecting the continued growth across our three U.S. resource plays partially offset by natural declines in Gulf of Mexico production. Extreme winter weather impacts on availability and completion operations negatively impacted production in the first quarter of 2014. Net natural gas sales volumes decreased 40 million cubic feet per day ("mmcfd") during the same period, due primarily to the cessation of production from operated wells in the Powder River Basin in Wyoming and to the sale of our Alaska assets in January 2013. These decreases were somewhat offset by increases in associated natural gas production from our U.S. resource plays.
Eagle Ford - Average net sales volumes from Eagle Ford were 96 mboed in the first quarter of 2014 compared to 72 mboed in the same period of 2013, for an increase of 33 percent. Approximately 65 percent of the first quarter of 2014 production was crude oil and condensate, 17 percent was natural gas liquids ("NGLs") and 18 percent was natural gas.
Individual well results were strong during the quarter and continued to consistently outperform the modeled type curves. With the transition to higher density pad drilling, from an average of three to four wells per pad, coupled with a period of rebuilding uncompleted well inventory, the number of wells we brought to sales was lower compared to the fourth quarter of 2013. During the first quarter of 2014, we reached total depth on 83 gross operated wells and brought 49 gross operated wells to sales compared to 76 reaching total depth and 69 brought to sales in the first quarter of 2013. Our first quarter average spud-to-total depth time was 14 days, which reflected the addition and ramp up of three new rigs and an increased number of wells with longer laterals, compared to 12 days in the same period of 2013.
We continued to progress co-development opportunities in the Austin Chalk. In early April, we brought online an Austin Chalk appraisal well, the Children Weston 4H, with a 30-day IP rate of 1,600 boed (76 percent liquid hydrocarbons) constrained at a 16/64 choke. This is our sixth Austin Chalk producer which continues the further appraisal of full Austin Chalk potential. Two additional Austin Chalk wells are waiting on completion and three more pilot groups, with a total of six Austin Chalk wells, are currently drilling.
Bakken - Average net sales volumes from the Bakken shale were 43 mboed in the first quarter of 2014 compared to 37 mboed in the same period of 2013, for an increase of 16 percent. Our Bakken production averages approximately 90 percent crude oil, 4 percent NGLs and 6 percent natural gas. During the first quarter of 2014, we reached total depth on 16 gross operated wells and brought 15 gross operated wells sales. Our first quarter average time to drill a well was 18 days spud-to-total depth, compared to 16 days in the same period of 2013. Both our drilling and completion activities were impacted by extraordinary winter weather in the first quarter of 2014.
We recompleted five wells during the first quarter of 2014 with favorable results in the Myrmidon area and have recently expanded south in the Hector area. We continue high density pilots to test 320-acre spacing for co-development with four Middle Bakken and four Three Forks wells per 1,280-acre spacing unit. Further high density pilots with up to 12 wells per 1,280-acre spacing unit are planned by the end of 2014.
Oklahoma resource basins - Net sales volumes from the Oklahoma resource basins averaged 15 mboed in the first quarter of 2014, for an increase of 15 percent over the same period of 2013. Importantly, liquid hydrocarbon volumes increased approximately 28 percent compared to the first quarter of 2013. During the first quarter of 2014, we reached total depth on five gross operated wells and brought four gross SCOOP wells to sales. The 30-day IP rates for the two SCOOP XL wells were 990 boed (70 percent liquid hydrocarbons) and 1,550 boed (66 percent liquid hydrocarbons). We have accumulated more than 100,000 net acres in the SCOOP area.
We continue to test other horizons in Oklahoma with two operated wells producing in the Southern Mississippi Trend and the first of two Granite Wash horizontal wells online. Two additional wells in the Southern Mississippi Trend are scheduled to spud in the second quarter of 2014.
Wyoming - Operated production at the Powder River Basin field ceased in March 2014. Plug and abandonment activities are expected to be completed in the fall of 2014.


Exploration
Gulf of Mexico - The Key Largo prospect, located on Walker Ridge Block 578, is anticipated to spud in the third quarter of 2014 as the first well with the new-build deepwater drillship. We are operator and hold a 60 percent working interest in the prospect.
We expect the second appraisal well on the non-operated Shenandoah prospect to be spud in the second quarter of 2014. The well will be located on Walker Ridge Block 51, in which we hold a 10 percent working interest.
We have farmed into the Perseus prospect located on Desoto Canyon Blocks 143, 187, 188, 230 and 231. A well is anticipated to spud in the second half of 2014. We hold a 30 percent non-operated working interest. International E&P
Production
Net liquid hydrocarbon and natural gas sales volumes averaged 197 mboed during the first quarter of 2014 compared to 265 mboed in the same period of 2013, a 26 percent decrease. We had no oil liftings in Libya in the first quarter of 2014 as a result of on-going third-party labor strikes at the Es Sider oil terminal. Excluding Libya, net sales volumes decreased 13 percent in the first quarter of 2014 compared to the first quarter of 2013 primarily as a result of significant unplanned downtime at the non-operated Foinaven field in the United Kingdom ("U.K.") and unplanned downtime at the methanol plant in Equatorial Guinea, as well as natural decline from North Sea assets and production curtailments at Alvheim in Norway due to severe winter weather.
Equatorial Guinea - Average net sales volumes were 108 mboed in the first quarter of 2014 compared to 111 mboed in the same period of 2013. During the first quarter of 2014, work was completed on scheduled offshore riser repairs, an unplanned repair at the methanol plant, as well as a planned 8-day partial shut-down at the LNG plant, which was accomplished ahead of schedule and under budget.
Norway - Average net sales volumes from Norway decreased 20 percent to 70 mboed in the first quarter of 2014 compared to 88 mboed in the same period of 2013, primarily reflecting natural field production decline. Alvheim was also impacted in the first quarter of 2014 by severe winter weather which resulted in eight days of curtailed production.
United Kingdom - Average net sales volumes were 18 mboed in the first quarter of 2014 compared to 28 mboed in the same period of 2013, a 36 percent decrease as a result of reliability issues at the non-operated Foinaven field, as well as natural decline and a delayed reinstatement of gas compression at Brae. During the second quarter of 2014, a turnaround is planned at Brae. The reliability issues at Foinaven continue into the second quarter of 2014 and will impact production and the timing of future liftings. Additionally, we expect a planned turnaround at Foinaven to begin in the second quarter and extend into the third quarter of 2014.
Libya - We have had no oil liftings in Libya since July 2013 due to ongoing third-party labor strikes at the Es Sider oil terminal. Despite reported progress at other terminals, the Es Sider oil terminal remains closed. Exploration
Kurdistan Region of Iraq - The Jisik-1 exploration well was spud on the Harir Block in December 2013. We expect the well to reach a projected total depth of 13,100 feet in the second quarter of 2014. Following the successful 2013 Mirawa-1 discovery, the Mirawa-2 appraisal well is expected to spud in the third quarter of 2014. We hold a 45 percent operated working interest in the Harir Block.
The Atrush-4 development well reached total depth on the Atrush Block in January 2014. Well testing was completed in April and the well has been suspended as a future producer. The Chiya Khere-5 development well (formerly Atrush-5), included in the previously approved Atrush development plan, is expected to spud in the second quarter of 2014. First oil from the Atrush Block is expected in 2015. We hold a 15 percent non-operated working interest in the Atrush Block. Kenya - The Sala-1 exploration well was spud in February 2014 on the eastern side of Block 9, where previous wells drilled had confirmed a working petroleum system. The Sala-1 is expected to reach a total depth of approximately 11,300 feet in the second quarter of 2014. We hold a 50 percent non-operated working interest in Block 9 with the option to operate any commercial development. Ethiopia - The Shimela-1 spud in March 2014 on the South Omo Block and is expected to reach a total depth of 8,850 feet in the second quarter of 2014. We hold a 20 percent non-operated interest in the South Omo Block.
We increased our acreage in Ethiopia through a farm-in to the Rift Basin Area Block with 10.5 million gross acres. We hold a 50 percent non-operated working interest in the block with the option to operate if a discovery is made. Gabon - In late October 2013, we were the high bidder as operator of the G13 deepwater block in the pre-salt play offshore Gabon. We have received a Model Production Sharing Contract ("PSC") from the Gabonese government and negotiations toward a final PSC are ongoing. Award of the block is subject to government approval.


Poland - During the first quarter of 2014, we relinquished our remaining 4 operated concessions to the government.
Oil Sands Mining
Our Oil Sands Mining operations consist of a 20 percent non-operated working interest in the AOSP. Our net synthetic crude oil sales volumes were 47 mbbld in the first quarter of 2014 compared to 51 mbbld in the same period of 2013, as a result of lower mine reliability and nine days of planned mine maintenance. We expect a planned turnaround in the second quarter of 2014. Acquisitions and Dispositions
In the first quarter of 2014, we closed the sales of our non-operated 10 percent working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion. See Note 5 to the consolidated financial statements for information about these dispositions.
The above discussions include forward-looking statements with respect to future drilling plans, exploration drilling activity in the Gulf of Mexico, Ethiopia, the Kurdistan Region of Iraq and Kenya, the timing of first production for the Atrush Block, the award of one block in Gabon, planned turnarounds at Foinaven, Brae, and oil sands mining, the possible sale of the U.K. and Norway businesses, and the common stock repurchase program. The reported average number of days to drill a well may not be indicative of the number of days to drill a well in the future. The current or initial production rates may not be indicative of future production rates. Factors that could potentially affect future drilling plans, exploration drilling activity in the Gulf of Mexico, Ethiopia, the Kurdistan Region of Iraq and Kenya, and the timing of first production for the Atrush Block include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, the inability to obtain or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other geological, operating and economic considerations. The award of the block in Gabon is subject to government approval and negotiation of an exploration and production sharing contract. The planned turnarounds at Foinaven, Brae, and oil sands mining are based on current expectations and good faith projections and are not guarantees of future performance. The possible sale of the U.K. and Norway businesses is subject to the identification of one or more buyers, board approval, successful negotiations, and execution of definitive agreements. The common stock repurchase program could be affected by changes in the prices of and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of our exploration or production operations, unforeseen hazards such as weather conditions or acts of war or terrorist acts and other operating and economic considerations. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Market Conditions
Prevailing prices for the various qualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows. The following table lists benchmark crude oil and natural gas price averages relative to our North America E&P and International E&P segments in the first quarters of 2014 and 2013.

                                                           Three Months Ended March
                                                                      31,
Benchmark                                                     2014          2013
West Texas Intermediate ("WTI") crude oil (Dollars per
barrel)                                                        $98.62        $94.36
Brent (Europe) crude oil (Dollars per barrel)                 $108.17       $112.49
Henry Hub natural gas (Dollars per million British
thermal units ("mmbtu"))(a)                                     $4.94         $3.34


(a)  Settlement date average.

North America E&P
Liquid hydrocarbons - The quality, location, and composition of our liquid hydrocarbon production mix can cause our North America E&P price realizations to differ from the WTI benchmark.
Quality - Light sweet crude contains less sulfur and tends to be lighter than sour crude oil so that refining it is less costly and has historically produced higher value products; therefore, light sweet crude is considered of higher quality and has historically sold at a price that approximates WTI or at a premium to WTI. The percentage of our North America E&P crude oil and condensate production that is light sweet crude has been increasing. In the first quarter of 2014, the percentage of our U.S. crude oil and condensate production that was sweet averaged 79 percent compared to 74 percent in the same period of 2013.


Location - In recent years, crude oil sold along the U.S. Gulf Coast, such as that from the Eagle Ford, has been priced based on the Louisiana Light Sweet ("LLS") benchmark which has historically priced at a premium to WTI and has historically tracked closely to Brent, while production from inland areas farther from large refineries has been priced lower. The average WTI discount to Brent has narrowed in 2014. In first quarter of 2014, the WTI discount to Brent was $9.55 compared to $18.13 in the same period of 2013. As a result of significant increases in U.S. production of light sweet crude oil, the historical relationship between WTI, Brent and LLS pricing may not be indicative of future periods.
Composition - The proportion of our liquid hydrocarbon sales that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were 15 percent of our North America E&P liquid hydrocarbon sales volumes in the first quarter of 2014 compared to 14 percent in the same period of 2013.
Natural gas - A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas. Average Henry Hub settlement prices for natural gas were 48 percent higher for the first quarter of 2014 than in the same period of 2013. International E&P
Liquid hydrocarbons - Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude benchmark, which was 4 percent lower in the first quarter of 2014 than in the same period of 2013. Natural gas - Our major international natural gas-producing regions are Europe and Equatorial Guinea. Natural gas prices in Europe have been considerably higher than in the U.S. in recent years. In the case of Equatorial Guinea, our natural gas sales are subject to term contracts, making realized prices in these areas less volatile. The natural gas sales from Equatorial Guinea are at fixed prices; therefore, our reported average natural gas realized prices may not fully track market price movements.
Oil Sands Mining
The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third has historically tracked movements in the Canadian heavy crude oil marker, primarily Western Canadian Select ("WCS"). The WCS discount to WTI in the first quarter of 2014 decreased 28 percent when compared to the same period of 2013.
The operating cost structure of our Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude oil prices.
The table below shows benchmark prices that impacted both our revenues and variable costs for the first quarters of 2014 and 2013:

                                                          Three Months Ended March 31,
Benchmark                                                      2014          2013
WTI crude oil (Dollars per barrel)                                $98.62        $94.36
WCS crude oil (Dollars per barrel)(a)                             $75.55      $62.41
AECO natural gas sales index (Dollars per mmbtu)(b)                $4.99       $3.16

(a) Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

(b) Monthly average AECO day ahead index.

Results of Operations
Consolidated Results of Operation
Net income per diluted share was $1.65 in the first quarter of 2014, up over 200 percent from the same period of 2013 primarily due to the $0.83 per diluted share after-tax gain on the sale of our Angola assets and a reduction in exploration expenses. The effective tax rate for continuing operations was 52 percent in the first quarter of 2014 compared to 72 percent in the first quarter of 2013. This decrease was primarily due to higher projected 2014 annual ordinary income from our North American operations, which are in a lower tax jurisdiction, and pretax losses in Libya in the first quarter of 2014, compared to pretax income in Libya during the same period of 2013, where the tax rates are in excess of 90 percent. Income from continuing operations per diluted share was $0.77, an increase of 43 percent from the first quarter of 2013, primarily due to the reduction in exploration expenses and the change in the income mix to lower tax jurisdictions.


Sales and other operating revenues, including related party are summarized by segment in the following table:

                                                            Three Months Ended March 31,
(In millions)                                                   2014             2013
Sales and other operating revenues, including related
party
North America E&P                                          $       1,392     $    1,215
International E&P                                                  1,061          1,801
Oil Sands Mining                                                     377            388
Segment sales and other operating revenues, including
related party                                                      2,830          3,404
Unrealized loss on crude oil derivative instruments                    -            (50 )
Sales and other operating revenues, including related
party                                                      $       2,830     $    3,354

North America E&P sales and other operating revenues increased $177 million in the first quarter of 2014 compared to the same period of 2013 primarily due to higher net liquid hydrocarbon sales volumes resulting from the continued growth across our three U.S. resource plays partially offset by slightly lower liquid hydrocarbon price realizations compared to the same period of 2013. The following table gives details of net sales volumes and average price realizations of our North America E&P segment:

                                                            Three Months Ended March 31,
                                                                 2014           2013
North America E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld) (a)                     163           141
Liquid hydrocarbon average price realizations (per
bbl) (b) (c)                                                        $84.79        $86.14
Net crude oil and condensate sales volumes (mbbld)                   138           121
   Crude oil and condensate average price realizations
(per bbl) (b)                                                       $92.48        $94.68
   Net natural gas liquids sales volumes (mbbld)                      25            20
   Natural gas liquids average price realizations (per
bbl) (b)                                                            $43.11        $35.48
Net natural gas sales volumes (mmcfd)                                300           340
Natural gas average price realizations (per mcf)(b)                  $5.28         $3.86


(a)  Includes crude oil, condensate and natural gas liquids.

(b) Excludes gains and losses on derivative instruments.

(c) Inclusion of realized losses on crude oil derivative instruments would have . . .

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