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					                                                                               MORGAN             STANLEY             RESEARCH
                                                                               NORTH          AMERICA


                                                                               Morgan Stanley & Co. LLC            Evan Calio
                                                                                                                   Evan.Calio@morganstanley.com
                                                                                                                   +1 212 761 6472

                                                                                                                   Ben Hur
                                                                                                                   Ben.Hur@morganstanley.com
                                                                                                                   +1 212 761 7827

                                                                                                                   Marko Lazarevic
                June 30, 2011                                                                                      Marko.Lazarevic@morganstanley.com
                                                                                                                   +1 212 761 3692


Industry View   Refining & Marketing                                                                               Todd Firestone
                                                                                                                   Todd.Firestone@morganstanley.com
                                                                                                                   +1 212 761 7674
Attractive
                Mid-Con Refining on the Toll
                                                                               Refining & Marketing Price Targets
                Road of Production Growth,                                                         Current             Revised Valuation

                Part II - Raising Estimates                                    Company
                                                                               Holly
                                                                                                     Price
                                                                                                   $68.18
                                                                                                                     Base
                                                                                                                    $84.00
                                                                                                                                Bull
                                                                                                                              $98.00
                                                                                                                                                    Bear
                                                                                                                                                  $64.00
                                                                               Frontier            $32.76           $40.00    $47.00              $31.00
                Raising price targets on refiners by 20% on our higher         Western             $17.63           $21.00    $26.00              $15.00
                Mid-Con differential forecasts of $15/bbl in 2011 (vs. prior   Valero              $24.95           $29.00    $31.00              $23.00
                $11) and $15/bbl in 2012 (vs. $8). Our new quarterly           Tesoro              $22.12           $26.00    $28.00              $20.00
                Cushing balance model supports our forecast spreads.           Delek US            $14.88           $17.00    $20.00              $13.00
                “Bull case”: Cushing fills in 2Q12e, driving a $50 spread.     Alon USA            $10.84           $11.00    $13.00               $9.00


                We think higher Mid-Con differentials will be the                                                       Upside to Current
                primary investment theme in US refining through                Company            Rating              Base        Bull     Bear
                                                                               Holly               OW                  23%       44%        -6%
                2012 — the most impactful and the least sensitive to
                                                                               Frontier            OW                  22%       43%        -5%
                macro uncertainty (see our February 2 note). We
                                                                               Western             OW                  19%       47%       -15%
                believe the Mid-Con differential advantage is becoming
                                                                               Valero              EW                  16%       24%        -8%
                consensus and the equities price ~$10/bbl spread vs.
                                                                               Tesoro              EW                  18%       27%       -10%
                our $15 forecast (WTI/LSS). Our Overweights,
                                                                               Delek US            EW                  14%       34%       -13%
                FTO/HOC (HFC) and WNR, possess modestly more
                                                                               Alon USA            UW                   1%       20%       -17%
                upside than peers on our base case scenario; but
                                                                               Average                                16%        34%      -10%
                40-45% upside to our “bull case.” Based on our                 Source: Morgan Stanley Research
                proprietary Cushing balance model, we believe there is         Note: Our base case values are our price targets

                a high likelihood that the spread reaches $50 in 2Q12 to
                                                                               Table of Contents                                               Page
                drive shut-ins as Cushing reaches full storage capacity.
                                                                               Executive Summary and What's New                                 2
                Mid-Con leverage drives additional upside to                   Resume Coverage: Overweight HOC and FTO                          4
                exposed names FTO, HOC, WNR, and DK. We are                    Valuing Differentials and Refining Equities                      5
                doubling our 2012e EPS, with upside to our estimates.          Inbound Cushing Crude Oil Production Growth                      15
                Using our new framework, we value refiners based on            Takeaway Capacity from Cushing                                   29
                disaggregating: (1) the value of the Mid-Con differential      Refining Risk-Reward Snapshots                                   36
                (DCF) and (2) the value of remaining global margin             Refining Comparable Metrics                                      46
                (EV/EBITDA). We believe Mid-Con refining equities
                price ~$10/bbl WTI/LLS differential.

                Storage economics and shipping costs support our
                forecast. We base our differential on storage
                economics at Cushing until new pipelines allow an exit,
                requiring a ~$15/bbl differential. The cost to transport the   Morgan Stanley does and seeks to do business with
                marginal barrel around Cushing supports a $15/bbl              companies covered in Morgan Stanley Research. As
                spread until 2013 and a $4/bbl spread for new pipeline         a result, investors should be aware that the firm may
                                                                               have a conflict of interest that could affect the
                tariffs thereafter.
                                                                               objectivity of Morgan Stanley Research. Investors
                                                                               should consider Morgan Stanley Research as only a
                Our new Cushing balance model is based on a                    single factor in making their investment decision.
                detailed quarterly model matching crude production
                                                                               For analyst certification and other important
                growth and all forms of takeaway capacity.                     disclosures, refer to the Disclosure Section,
                                                                               located at the end of this report.
                                                                  MORGAN                                                STANLEY                   RESEARCH

                                                                  June 30, 2011
                                                                  Refining & Marketing




Executive Summary: WTI Differentials Structurally Wider
Mid-Con refining benefits from US unconventional oil               refiners 30% on average, for average upside of 16% to current
boom and pipeline latency. We expect the US                        share prices.
unconventional oil boom (centered in Mid-Con) and Canadian
growth to create storage issues at Cushing, Oklahoma, until        Exhibit 1

new pipeline capacity is constructed in 2013. The effects will     Production Growth Affecting Cushing
be similar to the discovery of significant unconventional gas                                                                                                                                       (kbd)
                                                                                                             Alberta Bakken
resource in 2008, which structurally damaged the US natural                                                  Mississippian Lime                                                                     6,000
                                                                                                             Woodford
gas markets and created the fall ritual of full natural gas                                                  Niobrara
                                                                                                                                                                                                    5,000
                                                                                                             Bakken
storage. Mid-Con refiners exposed to WTI, WTI-linked crude,                                                  Canada (ex. Oil Sands)
or Canadian heavy-light differentials stand to benefit                                                       Oil Sands (Mining & In-Situ)                                                           4,000
                                                                                                             Permian
significantly. We modeled production growth in each basin
                                                                                                                                                                                                    3,000
and Canadian crude oil production growth in our new Cushing
balance model (page 9). We believe there is modest upside                                                                                                                                           2,000
from “new” potential liquid plays where results are expected
                                                                                                                                                                                                    1,000
from several potential new plays in the next 12 months.
                                                                                                                                                                                                    0
We believe wider differentials at Cushing will continue                         2000                            2002      2004        2006        2008         2010     2012        2014     2016
through 2012 with 1Q and 4Q seasonal peaks. While we               Source: Company data, Morgan Stanley Research estimates
expect that current record spreads of ~$17.50/bbl YTD
(WTI/LLS) will recede in 3Q11, we believe secular pressures        Exhibit 2
will drive WTI-LLS (rather than Brent) differentials to average    Cushing Storage Fills Driving Shut-in Production
$15/bbl going forward, versus historical parity, until 2Q13.       and Our Bull Case Differentials
Our new, proprietary model, forecasts quarterly Cushing                                                                          Cushing Storage Utilization     Shut-in Production (mbpd)
                                                                                                      100%                                                                                          1,000
storage utilization, and demonstrates an inverse seasonality
                                                                                                      90%                                                                                           900
with spreads peaking in 1Q and 4Q, during historically weaker
                                                                    Cushing Storage Utilization (%)




                                                                                                      80%                                                                                           800




                                                                                                                                                                                                            Shut-in Production (mbpd)
refining quarters. We also see a high probability of our new                                          70%                                                                                           700
“Bull case” that Cushing storage will fill in 2Q2012 and force                                        60%                                                                                           600

up to $50/bbl differentials and shut-in 80mmbbls (885 mbpd)                                           50%                                                                                           500

of production at peak in 1Q13. Additional refining capacity,                                          40%                                                                                           400

higher utilization, the reversal of the Longhorn pipeline, new                                        30%                                                                                           300

                                                                                                      20%                                                                                           200
Cushing storage capacity and, eventually, new pipeline
                                                                                                      10%                                                                                           100
capacity to the Gulf will help balance the market by 2013.
                                                                                                       0%                                                                                           0
Post mid-2013, we believe Cushing to Gulf Coast tariffs of
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~$4/bbl will define the terminal differential.
                                                                   Source: Company data, Morgan Stanley Research estimates

FTO, HOC, WNR, and DK have significant exposure to
                                                                   Exhibit 3
this structural shift. We expect materially higher gross
                                                                   Valuation Leverage to $2 Differential Change
margin realizations from refiners that can run and access WTI
                                                                                                                             WTI Differential ($/bbl Through mid-13 and Terminal)
or WTI-linked crudes, which includes less than 25% of US                                                                $9/$2.50 $11/$3.00 $13/$3.50 $15/$4.00 $17/$4.50 $19/$5.00
capacity and ~5% global capacity. We see the most leverage         VLO                                          24.95    $26.86     $27.53      $28.21    $28.89     $29.57   $30.25
                                                                   TSO                                          22.12    $22.10     $23.34      $24.58    $25.83     $27.07   $28.31
in FTO and HOC, which each (and as merged) has the ability         WNR                                          17.63    $15.78     $17.63      $19.48    $21.33     $23.18   $25.03
to run 100% WTI-linked crude. Given the recent                     DK                                           14.88    $14.06     $15.02      $15.99    $16.95     $17.92   $18.88
outperformance, we don’t see near-term as compelling yet           ALJ                                          10.84      $8.13     $9.14      $10.16    $11.17     $12.18   $13.20
                                                                   FTO                                          32.76    $32.52     $35.09      $37.66    $40.23     $42.80   $45.37
believe our Bull case ($50 spread) is more probable and            HOC                                          68.18    $70.72     $74.99      $79.26    $83.53     $87.79   $92.06
drives 40-45% upside potential. Our revised 2012 EPS               Source: Company data, Morgan Stanley Research estimates
estimates are 100% above Street for FTO, 101% for HOC,
and 112% for WNR. We are raising our price targets on




                                                                                                                                                                                                                     2
                                                                                                                                                                 MORGAN                                                                                              STANLEY                                                                                 RESEARCH

                                                                                                                                                                 June 30, 2011
                                                                                                                                                                 Refining & Marketing




 What’s New in “Toll Road to Production Growth, Part II?”
Mid-Con goes mainstream. Since late January, the Mid-Con                                                                                                         become relevant; and (4) lastly provide more detail on
names have outperformed peers, experienced material                                                                                                              production growth, potential production upside, and ability of
positive EPS revisions and the WTI/LLS and WTI/Brent                                                                                                             barge truck and rail to arbitrage the spread.
differentials have remained wider despite Cushing drawing
                                                                                                                                                                 Exhibit 5
barrels in each of the last 3 months. The Mid-Con benefit has
                                                                                                                                                                 WTI Differentials Has Widened Since Early 2011
clearly moved more within consensus.
                                                                                                                                                                  $10.00                                                                                                                                                                                        WTI-LLS                                            WTI-Brent

Exhibit 4
                                                                                                                                                                           $5.00
Pure Mid-Con Refiners Have Led Performance YTD
                                                                                                                                                                           $0.00
                                                            Pure Mid-Con Refiners       Mid-Con Exposed Refiners          Energy            S&P 500
                                    300
                                                                                                                                                                   ($5.00)
                                                                               "Mid-Con: Toll Road" Report
                                    250
                                                                                                                                                                  ($10.00)
  Indexed Returns (6/25/10 = 100)




                                    200                                                                                                                           ($15.00)



                                    150                                                                                                                           ($20.00)


                                                                                                                                                                  ($25.00)




                                                                                                                                                                                                                                                                               May-07




                                                                                                                                                                                                                                                                                                                                                    May-08




                                                                                                                                                                                                                                                                                                                                                                                                                           May-09




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              May-10




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 May-11
                                                                                                                                                                                                                                              Nov-06


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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  Nov-10


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        Mar-11
                                                                                                                                                                                                                     Jul-06
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                                                                                                                                                                                                                                                          Jan-07




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                                                                                                                                                                                                                                                                                                                                                               Jul-08
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                                                                                                                                                                                                                                                                                                                                                                                                                                       Jul-09
                                                                                                                                                                                                                                                                                                                                                                                                                                                  Sep-09


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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               Jan-11
                                    100



                                     50
                                                                                                                                                                 Source: Company data, Morgan Stanley Research

                                      0                                                                                                                          Exhibit 6
                                                                                                                                                        May-11
                                          Jun-10



                                                   Jul-10




                                                            Aug-10




                                                                      Sep-10



                                                                               Oct-10




                                                                                         Nov-10



                                                                                                  Dec-10




                                                                                                             Jan-11




                                                                                                                      Feb-11



                                                                                                                                   Mar-11




                                                                                                                                               Apr-11




                                                                                                                                                                 WTI Discount Leads Higher EPS Estimates
Source: FactSet, Morgan Stanley Research                                                                                                                                                                                                                           Pure Mid-Con Refiners                                                                       Mid-Con Exposed Refiners                                                                                    Energy                                        S&P 500
                                                                                                                                                                                                                  450

                                                                                                                                                                                                                  400
                                                                                                                                                                                                                                                                                                                                  "Mid-Con Toll Road"
                                                                                                                                                                   Indexed EPS Revision (6/25/10 = 100)




Why write the note? We continue to see material upside                                                                                                                                                                                                                                                                                         Report
                                                                                                                                                                                                                  350
and generally less risk of a narrowing spread vs. risks to
                                                                                                                                                                                                                  300
global cracks and hence are raising our estimates, targets and
                                                                                                                                                                                                                  250
updating our views since our Mid-Con Refining on the Toll
                                                                                                                                                                                                                  200
Road to Production Growth (February 2, 2011).
                                                                                                                                                                                                                  150


In this note we also are adding several new elements that                                                                                                                                                         100


we believe are relevant including: (1) a more detailed model                                                                                                                                                      50


of Cushing balance (Cushing inventory is the bottom line) that                                                                                                                                                      0




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             May-11
                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 Mar-11
                                                                                                                                                                                                                                                                                                                                                                   Nov-10
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                                                                                                                                                                                                                                                       Jul-10


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                                                                                                                                                                                                                                                                                                              Sep-10


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                                                                                                                                                                                                                                                                                                                                                                                                                                                            Feb-11




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                Apr-11
address several elements (a) the ability to get growth barrels to
Cushing, as pipeline constraints are two way - both in-bound                                                                                                     Source: FactSet, Morgan Stanley Research
and outbound to Cushing, (b) introduce a quarterly model to
                                                                                                                                                                 Exhibit 7
see seasonality and allow an entire systems check each
                                                                                                                                                                 Market Increasing Expectations for WTI-Brent
quarter by actual vs. forecasted Cushing inventory, (c)
                                                                                                                                                                                                                                                                                                          Jun-24                                         Apr-29                                        Mar-31                                          Feb-28                                          Feb-01
introduce and quantify our "Bull" case when Cushing fills and                                                                                                                                                     $16.00


drives a spread of $50/bbl that prices shut in production; (2)                                                                                                                                                    $14.00
                                                                                                                                                                       Futures Implied Brent-WTI Spread ($/bbl)




expand on our Mid-Con valuation method introduced in                                                                                                                                                              $12.00

"What’s in the Mid-con Price" (March 25, 2011) that uses a                                                                                                                                                        $10.00

DCF valuation on the spread rather than a peak multiple on
                                                                                                                                                                                                                   $8.00
peak EBITDA and also includes a terminal spread of $4/bbl
                                                                                                                                                                                                                   $6.00
equal to the new Cushing exit pipeline tariff; (3) introduce
Cushing storage economics as another method to calculate                                                                                                                                                           $4.00


spread - i.e. what is the differential that allows you to store, hold,                                                                                                                                             $2.00

earn a return and ship a barrel to the Gulf Coast to arbitrage the                                                                                                                                                 $0.00
                                                                                                                                                                                                                                     Aug-11

                                                                                                                                                                                                                                                        Oct-11

                                                                                                                                                                                                                                                                      Dec-11

                                                                                                                                                                                                                                                                                        Feb-12

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                                                                                                                                                                                                                                                                                                                                         Aug-12

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                                                                                                                                                                                                                                                                                                                                                                        Dec-12

                                                                                                                                                                                                                                                                                                                                                                                     Feb-13

                                                                                                                                                                                                                                                                                                                                                                                                       Apr-13

                                                                                                                                                                                                                                                                                                                                                                                                                         Jun-13

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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     Feb-14

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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         Jun-14

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                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      Dec-14




spread, because as Cushing grows storage capacity beyond a
level to support the Mid-Con system, storage economics
                                                                                                                                                                 Source: Bloomberg, Morgan Stanley Research




                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          3
                                                                                           MORGAN         STANLEY      RESEARCH

                                                                                           June 30, 2011
                                                                                           Refining & Marketing




Raising Refining Earnings Estimates and Price Targets
We are raising our estimates by an average of 101% and                                     10% of total earnings with no Mid-Con exposure. We base our
price targets by an average of 31%. Our forecast is driven by                              price targets on a DCF for the WTI differential benefit, including
changes in the WTI/LLS differential, where we are raising our                              the bullet cash flow stream through 2013 as well as the terminal
forecast to $15/bbl through mid-2013 from a previous $8/bbl.                               WTI/LLS differential, along with a mid-cycle EV/EBITDA
We note all independent refiners (ex-SUN) have Mid-Con                                     multiple applied to the underlying economic EBITDA, which is
exposure in varying degrees (10-100%). Our forecast for the                                generated agnostic of the WTI/LLS differential. Risks to our
underlying economic crack spreads (LLS based) remain in line                               call include lower refined product demand, higher than
to slightly above consensus as we see modestly tighter global                              expected refinery supply, lower crude oil production from
distillate utilization in 2012. Strongest beneficiaries to higher                          liquids rich shale and Canadian oil sands, faster pipeline
WTI/LLS forecast include FTO, HOC, WNR, and DK, while                                      construction or reversals than expected, other takeaway
VLO, TSO, and ALJ are modestly impacted. We maintain our                                   capacity drains Cushing and inability of operators to run
estimates and price target for SUN, as we believe share price                              refining assets leading to lower utilization.
will be driven by restructuring, and R&M contributes less than
Exhibit 8
Revised R&M Earnings Estimates and Price Targets
                             MS Revised EPS                                             Consensus                                 % Difference
Company             2Q11       3Q11 FY2011                 FY2012                2Q11    3Q11 FY2011       FY2012       2Q11       3Q11 FY2011      FY2012
Valero             $1.48      $1.14    $4.16                $4.20               $1.41   $1.16  $3.61        $3.75         5%        -3%      15%      12%
Tesoro             $1.26      $0.89    $3.30                $3.66               $1.20   $0.85  $3.15        $2.74         4%         4%       5%      34%
Frontier           $1.52      $1.64    $5.80                $6.16               $1.15   $0.81  $3.89        $3.08        32%      101%       49%     100%
Holly              $3.00      $3.43   $11.06               $12.55               $2.17   $1.73  $6.82        $6.25        38%        98%      62%     101%
Western            $1.16      $1.61    $4.40                $5.19               $1.06   $0.78  $2.65        $2.45        10%      108%       66%     112%
Delek US           $0.71      $0.81    $2.35                $2.66               $0.56   $0.25  $1.31        $0.97        28%      221%       79%     174%
Alon USA           $0.64      $0.65    $2.08                $2.90               $0.42   $0.09  $0.72        $1.04        52%      592%      190%     178%
Average                                                                                                                 24%       160%       67%     101%

                             MS Revised EPS                                                 Prior                                 % Difference
Company             2Q11       3Q11 FY2011                 FY2012                2Q11    3Q11 FY2011       FY2012       2Q11      3Q11 FY2011       FY2012
Valero             $1.48      $1.14    $4.16                $4.20               $1.53   $1.24     $4.05      $2.97       -3%        -8%        3%     41%
Tesoro             $1.26      $0.89    $3.30                $3.66               $1.41   $1.13     $3.61      $2.52      -11%      -21%        -9%     45%
Frontier           $1.52      $1.64    $5.80                $6.16                  NA      NA        NA         NA        NM         NM        NM      NM
Holly              $3.00      $3.43   $11.06               $12.55                  NA      NA        NA         NA        NM         NM        NM      NM
Western            $1.16      $1.61    $4.40                $5.19               $1.16   $0.70     $2.50      $1.98        0%      129%       76%     162%
Delek US           $0.71      $0.81    $2.35                $2.66               $0.70   $0.36     $1.54      $1.05        1%      122%       53%     153%
Alon USA           $0.64      $0.65    $2.08                $2.90               $0.42   $0.02     $0.64     ($0.16)      52%         NM     223%       NM
Average                                                                                                                   8%       55%       69%     100%

                 Current           Revised Price Target     Implied                       Upside to Current            % Difference from Prior
Company            Price           Base      Bull     Bear EV/EBITDA                    Base       Bull     Bear        Base      Bull      Bear
Valero           $24.95           $29.00  $31.00    $23.00    3.7x                       16%      24%        -8%          7%       -3%       -4%
Tesoro           $22.12           $26.00  $28.00    $20.00    3.7x                       18%      27%       -10%          4%       -3%       -5%
Frontier         $32.76           $40.00  $47.00    $31.00    3.5x                       22%      43%        -5%          NM        NM        NM
Holly            $68.18           $84.00  $98.00    $64.00    4.5x                       23%      44%        -6%          NM        NM        NM
Western          $17.63           $21.00  $26.00    $15.00    3.4x                       19%      47%       -15%         17%      13%       15%
Delek US         $14.88           $17.00  $20.00    $13.00    3.7x                       14%      34%       -13%         89%      43%       63%
Alon USA         $10.84           $11.00  $13.00     $9.00    4.3x                        1%      20%       -17%         38%       -7%      29%
Average                                                                                 16%       34%      -10%         31%        8%       20%
Source: Morgan Stanley Research    Note: Our base case values are our price targets




                                                                                                                                                           4
                                                                                                          MORGAN                STANLEY           RESEARCH

                                                                                                          June 30, 2011
                                                                                                          Refining & Marketing




How We Value the Mid-Con Refiners and Differential Benefit
We believe there are currently three themes in US refining                                                connected to global supply and demand markets and we add
equities: (1) Mid-Con related crude feedstock differentials, (2)                                          transportation differential as the Mid-Con market (particularly
restructuring, (3) global macro trade, including call on refined                                          the southwest Mid-Con market) imports refined product and
product and asset supply/demand balance with select North                                                 therefore pays a premium to Gulf Coast product barrel in order
American exposed variables.                                                                               to bring it to market. We believe this deconstruction reflects the
                                                                                                          economic drivers of the Mid-Con margin and allows a better
Of these, we continue to see the Mid-Con feedstock                                                        valuation paradigm to translate the Mid-Con logistics
advantage element as the most powerful, impactful, and the                                                connection to cash flow sensitivities, valuation of the equities
least sensitive to macro uncertainty, leading to our higher                                               and a determination of what is in the price.
conviction on predictability. The restructuring theme is more
limited today than it was in 2010, yet still applicable for SUN,                                          Valuation of US refiners and Mid-Con exposure. We
WNR and an element in MPC (MLP potential). The global                                                     believe refiners are valued primarily off forward EBITDA and
macro trade, refined product and asset supply/demand                                                      often front-year estimates. Normalized margin-driven DCFs
balance call, with select North American exposed variables is                                             have had very limited effectiveness as a valuation of refining
beyond the focus of the note. The select North American                                                   equities, as macro-driven crack spreads have historically been
elements include a wider heavy-light and sweet-sour spread                                                the most challenging commodity to forecast over an extended
from lost Libyan production (also providing incremental export                                            duration. We build our base crack assumptions on a global
opportunities into Europe), cheaper hydrogen (natural gas)                                                macro distillate balance model, as distillation capacity, in our
costs and the US refined product export story (Latin American                                             view, is the tightest portion of the barrel. As margins move into
demand). We believe elements of the last theme, the more                                                  peak levels, we use compressed peak historical multiples to
traditional refining driver, is the hardest to forecast and, in our                                       value this segment. We believe, Mid-Con imbalances can be
opinion, why US refiners have the highest correlation to EPS                                              forecasted with greater (clearly not absolute) certainty and are
revisions and spot commodity prices (crack spreads) than any                                              appropriate to value on a DCF basis. We believe the market
energy sub-sector.                                                                                        looks at the differential as a bullet cash stream that will
                                                                                                          dissipate when take-away capacity added in sufficient level to
Building up to our new forecasts. In early February 2011,                                                 balance Cushing, in mid-2013. We also show our view, which
we deconstructed our cracks to reflect a wider WTI crude price                                            is a bullet DCF (now until mid-2013) and a residual value of the
differential and moved our upstream models to Brent price                                                 perpetuity differential. We believe the perpetuity differential will
forecast. We again deconstructed our Mid-Con marker                                                       be $4/bbl based on the tariff of new pipelines to the Gulf Coast.
crack-spreads to isolate the two elements that the drive the
margin; (1) the feed stock differential (WTI vs. LLS) and (2)                                             Our conclusions build our price targets. We back out the
base “economic” crack that is built up from a Gulf Coast LLS                                              “economic crack” and solve for Mid-Con DCF to show what
crack spread plus product transportation. We use the Gulf                                                 spread is “in the price” which is $10/bbl through mid-2013 vs.
Coast LLS crack as a US waterborne marker that is more                                                    $17.50 YTD and $15 in our new forecast.
Exhibit 9
Deconstruction of Mid-Con Refining Margins
                    $30                                               GC 3:2:1 Base Crack      Mid-Con Transport Differential    WTI/LLS Differential


                    $25


                    $20
            $/bbl




                    $15


                    $10


                     $5


                     $0
                      1Q/09   2Q/09   3Q/09   4Q/09   1Q/10   2Q/10    3Q/10   4Q/10   1Q/11    2Q/11E 3Q/11E 4Q/11E 1Q/12E 2Q/12E 3Q/12E 4Q/12E 1Q/13E 2Q/13E 3Q/13E 4Q/13E

Source: Bloomberg, Morgan Stanley Research estimates




                                                                                                                                                                               5
                                                                                      MORGAN        STANLEY       RESEARCH

                                                                                      June 30, 2011
                                                                                      Refining & Marketing




Exhibit 10
Valuation Sensitivity Using Bullet DCF + Base Crack EBITDA Multiple
             Current                                      Valuation and Sensitivity to WTI Diff. (Economic Value + Bullet DCF)
Ticker         Price        $3.00         $5.00            $7.00     $9.00     $11.00     $13.00     $15.00    $17.00     $19.00   $21.00   $23.00
VLO          $24.95        $24.14        $24.47           $24.81    $25.15     $25.48     $25.82     $26.15    $26.49     $26.83   $27.16   $27.50
TSO          $22.12        $17.10        $17.70           $18.30    $18.91     $19.51     $20.12     $20.72    $21.33     $21.93   $22.54   $23.14
WNR          $17.63         $8.37         $9.28           $10.20    $11.12     $12.04     $12.96     $13.88    $14.79     $15.71   $16.63   $17.55
DK           $14.88        $10.19        $10.66           $11.14    $11.62     $12.10     $12.58     $13.06    $13.54     $14.02   $14.50   $14.98
ALJ          $10.84         $4.07         $4.57            $5.07     $5.58      $6.08      $6.58      $7.09     $7.59      $8.09    $8.59    $9.10
FTO          $32.76        $22.23        $23.50           $24.78    $26.05     $27.33     $28.60     $29.87    $31.15     $32.42   $33.70   $34.97
HOC          $68.18        $53.62        $55.74           $57.85    $59.97     $62.09     $64.21     $66.32    $68.44     $70.56   $72.68   $74.79

                                              WTI Differential DCF Senstivity (Bullet DCF Benefit Only Through mid-2013, $/bbl)
                             $3.00         $5.00      $7.00      $9.00   $11.00       $13.00   $15.00     $17.00   $19.00     $21.00        $23.00
VLO          $24.95          $0.52         $0.86      $1.19      $1.53     $1.86       $2.20     $2.54     $2.87    $3.21       $3.55        $3.88
TSO          $22.12          $0.93         $1.54      $2.14      $2.75     $3.35       $3.95     $4.56     $5.16    $5.77       $6.37        $6.98
WNR          $17.63          $1.42         $2.33      $3.25      $4.17     $5.09       $6.01     $6.92     $7.84    $8.76       $9.68       $10.60
DK           $14.88          $0.74         $1.22      $1.70     $2.18      $2.66       $3.13     $3.61     $4.09    $4.57       $5.05        $5.53
ALJ          $10.84          $0.78         $1.28      $1.78      $2.28     $2.79       $3.29     $3.79     $4.29    $4.80       $5.30        $5.80
FTO          $32.76          $1.97         $3.24      $4.51     $5.79      $7.06       $8.34     $9.61    $10.89   $12.16     $13.44        $14.71
HOC          $68.18          $3.27         $5.38      $7.50     $9.62    $11.74       $13.85   $15.97     $18.09   $20.21     $22.32        $24.44

                                                  Economic Value (EBITDA Valuation of Underlying Crack Spread Profitability)
VLO          $24.95        $23.62        $23.62      $23.62    $23.62   $23.62     $23.62    $23.62     $23.62   $23.62            $23.62   $23.62
TSO          $22.12        $16.16        $16.16      $16.16    $16.16   $16.16     $16.16    $16.16     $16.16   $16.16            $16.16   $16.16
WNR          $17.63         $6.95         $6.95       $6.95     $6.95    $6.95      $6.95      $6.95     $6.95     $6.95            $6.95    $6.95
DK           $14.88         $9.45         $9.45       $9.45     $9.45    $9.45      $9.45      $9.45     $9.45     $9.45            $9.45    $9.45
ALJ          $10.84         $3.29         $3.29       $3.29     $3.29    $3.29      $3.29      $3.29     $3.29     $3.29            $3.29    $3.29
FTO          $32.76        $20.26        $20.26      $20.26    $20.26   $20.26     $20.26    $20.26     $20.26   $20.26            $20.26   $20.26
HOC          $68.18        $50.35        $50.35      $50.35    $50.35   $50.35     $50.35    $50.35     $50.35   $50.35            $50.35   $50.35

                                                   Economic Value Sensitivity (% Change in Crack Spread ex-WTI differential)
                             -50%          -40%        -30%      -20%       -10%        0%       10%       20%        30%             40%      50%
VLO            24.95       $11.89        $14.87      $17.53    $19.88     $21.90    $23.62    $25.02     $26.10    $26.88          $27.34   $27.50
TSO            22.12        $0.00         $0.60       $5.13     $9.23     $12.91    $16.16    $18.99     $21.39    $23.36          $24.91   $26.03
WNR            17.63        $0.00         $0.00       $0.25     $2.76      $4.99     $6.95     $8.63     $10.04    $11.17          $12.03   $12.60
DK             14.88        $3.26         $4.80       $6.18     $7.42      $8.51     $9.45    $10.24    $10.88     $11.37          $11.71   $11.91
ALJ            10.84        $0.00         $0.00       $0.00     $0.05      $1.78     $3.29     $4.58      $5.63      $6.46          $7.06    $7.43
FTO            32.76       $13.74        $15.39      $16.87    $18.17     $19.30    $20.26    $21.05    $21.66     $22.10          $22.37   $22.47
HOC            68.18       $15.11        $23.79      $31.65    $38.70     $44.93    $50.35    $54.96    $58.75     $61.73          $63.90   $65.25
Source: Company data, Morgan Stanley Research estimates




                                                                                                                                                 6
                                                                                 MORGAN        STANLEY     RESEARCH

                                                                                 June 30, 2011
                                                                                 Refining & Marketing




Exhibit 11
Valuation Sensitivity Using Bullet DCF + Terminal Differential DCF + Base Crack EBITDA Multiple
             Current       Valuation Sensitivity to WTI Diff. (Economic Value + WTI Benefit Through mid-2013 & Terminal Diff.)
Ticker         Price $3/$1.00 $5/$1.50 $7/$2.00 $9/$2.50 $11/$3.00 $13/$3.50 $15/$4.00 $17/$4.50 $19/$5.00 $21/$5.50 $23/$6.00
VLO          $24.95 $24.82 $25.50 $26.18 $26.86                $27.53   $28.21    $28.89      $29.57   $30.25    $30.93      $31.60
TSO          $22.12 $18.37 $19.61 $20.86 $22.10                $23.34   $24.58    $25.83      $27.07   $28.31    $29.56      $30.80
WNR          $17.63 $10.23 $12.08 $13.93 $15.78                $17.63   $19.48    $21.33      $23.18   $25.03    $26.88      $28.73
DK           $14.88 $11.16 $12.12 $13.09 $14.06                $15.02   $15.99    $16.95      $17.92   $18.88    $19.85      $20.82
ALJ          $10.84    $5.09    $6.10    $7.12      $8.13       $9.14    $10.16   $11.17      $12.18   $13.20    $14.21      $15.22
FTO          $32.76 $24.82 $27.38 $29.95 $32.52                $35.09   $37.66    $40.23      $42.80   $45.37    $47.94      $50.50
HOC          $68.18 $57.92 $62.19 $66.45 $70.72                $74.99   $79.26    $83.53      $87.79   $92.06    $96.33    $100.60

                                  WTI Differential DCF Senstivity (WTI Benefit Through mid-2013 & Terminal Differential, $/bbl)
                         $3/$1.00 $5/$1.50 $7/$2.00 $9/$2.50 $11/$3.00 $13/$3.50 $15/$4.00 $17/$4.50 $19/$5.00 $21/$5.50 $23/$6.00
VLO          $24.95        $1.20    $1.88    $2.56     $3.24      $3.92     $4.59      $5.27     $5.95     $6.63       $7.31     $7.99
TSO          $22.12        $2.21    $3.45    $4.69     $5.94      $7.18     $8.42      $9.66    $10.91   $12.15       $13.39    $14.63
WNR          $17.63        $3.28    $5.13    $6.98     $8.83     $10.68    $12.53    $14.38     $16.23   $18.08       $19.93    $21.78
DK           $14.88        $1.71    $2.68    $3.64     $4.61      $5.57     $6.54      $7.51     $8.47     $9.44      $10.40    $11.37
ALJ          $10.84        $1.80    $2.81    $3.82     $4.84      $5.85     $6.86      $7.88     $8.89     $9.90      $10.92    $11.93
FTO          $32.76        $4.55    $7.12    $9.69 $12.26        $14.83    $17.40    $19.97     $22.54   $25.11       $27.67    $30.24
HOC          $68.18        $7.57 $11.83 $16.10 $20.37            $24.64    $28.91    $33.17     $37.44   $41.71       $45.98    $50.24

                                                 Economic Value (EBITDA Valuation of Underlying Crack Spread Profitability)
VLO          $24.95       $23.62       $23.62      $23.62 $23.62     $23.62    $23.62    $23.62     $23.62    $23.62        $23.62     $23.62
TSO          $22.12       $16.16       $16.16      $16.16 $16.16     $16.16    $16.16    $16.16     $16.16    $16.16        $16.16     $16.16
WNR          $17.63        $6.95        $6.95       $6.95   $6.95     $6.95     $6.95      $6.95     $6.95     $6.95         $6.95      $6.95
DK           $14.88        $9.45        $9.45       $9.45   $9.45     $9.45     $9.45      $9.45     $9.45     $9.45         $9.45      $9.45
ALJ          $10.84        $3.29        $3.29       $3.29   $3.29     $3.29     $3.29      $3.29     $3.29     $3.29         $3.29      $3.29
FTO          $32.76       $20.26       $20.26      $20.26 $20.26     $20.26    $20.26    $20.26     $20.26    $20.26        $20.26     $20.26
HOC          $68.18       $50.35       $50.35      $50.35 $50.35     $50.35    $50.35    $50.35     $50.35    $50.35        $50.35     $50.35

                                                  Economic Value Sensitivity (% Change in Crack Spread ex-WTI differential)
                            -50%         -40%        -30%    -20%       -10%         0%       10%       20%        30%           40%      50%
VLO             24.95     $11.89       $14.87      $17.53 $19.88     $21.90      $23.62    $25.02    $26.10     $26.88        $27.34   $27.50
TSO             22.12      $0.00        $0.60       $5.13   $9.23    $12.91      $16.16    $18.99    $21.39     $23.36        $24.91   $26.03
WNR             17.63      $0.00        $0.00       $0.25   $2.76      $4.99      $6.95     $8.63    $10.04     $11.17        $12.03   $12.60
DK              14.88      $3.26        $4.80       $6.18   $7.42      $8.51      $9.45    $10.24    $10.88     $11.37        $11.71   $11.91
ALJ             10.84      $0.00        $0.00       $0.00   $0.05      $1.78      $3.29     $4.58     $5.63      $6.46         $7.06    $7.43
FTO             32.76     $13.74       $15.39      $16.87 $18.17     $19.30      $20.26    $21.05    $21.66     $22.10        $22.37   $22.47
HOC             68.18     $15.11       $23.79      $31.65 $38.70     $44.93      $50.35    $54.96    $58.75     $61.73        $63.90   $65.25
Source: Company data, Morgan Stanley Research estimates




                                                                                                                                            7
                                                                      MORGAN        STANLEY       RESEARCH

                                                                      June 30, 2011
                                                                      Refining & Marketing




Introducing Our New Cushing Balance Model
We significantly modified and expanded our Mid-Con                    the Mid-Con refineries, where higher refining capacity will
crude balance model from February 2, 2011 to include: (1)             reduce marginal crude flows into Cushing. We also model
our basin-by-basin production growth model: (2) examined the          turnarounds based on historical quarterly utilization adjusted
ability of Mid-Con and Canadian pipeline architecture to get          by our forecast of turnarounds and likely higher underlying
crude to the Cushing bottleneck; and (3) the availability of          utilization as refineries attempt to capture wider WTI
pipeline, truck, rail or barge to move crude out of Cushing. We       differentials. We then look at all possible ways to divert crude
now utilize a quarterly forecast with estimated turnaround data.      away from Cushing and evacuate crude to the Gulf Coast. We
Our analysis examined all existing and planned oil pipelines in       include major pipeline takeaway capacity, pipeline reversals,
the Mid-Con, current pipeline capacity to move production             as well as high cost transportation of rail, barge, and truck. The
growth into the Mid-Con, a basin-by-basin crude production            net amount of crude oil flowing into Cushing is added to current
build-up, all refinery expansions, all planned and historical         storage, and we forecast future additions to storage. The total
turnarounds for Mid-Con, all storage growth in Cushing and            Cushing storage compared to our storage capacity results in
Alberta, examination of rail, barge and truck markets. Based          our Cushing utilization forecast, which drives our WTI/LLS
upon our conclusions, we are raising our forecast for WTI-LLS         differential forecast
differential, and all associated Mid-Con related (WTI) crude
discounts to ~$15/bbl from $8/bbl through 2Q13. We assume             The key take-aways from our model include:
on average a 90% capture rate on that differential. Our
expanded model links all barrels flowing in and out of Cushing        (1) The spread remained wide despite recent Cushing draws
to calculate Cushing storage levels and utilization of total          which in our view supports the view that the Cushing storage
storage on a quarterly basis. We believe the Cushing storage          economics support the spread despite seasonally less
utilization is the bottom line because it is the net calculation of   pressure into Cushing vs. demand;
an entire system that is essentially an island until exit capacity
is constructed and brought on-line (2013).                            (2) Cushing storage is initially filled in 2Q12and peaking in
                                                                      1Q13 with 80mmbbls (885 mpd flowing) extra barrels with
We built a play-by-play basin model forecasting                       “no-way” out and “no where to go” - the trigger point for
production growth across North America, we then                       potential production shut-ins in our view,
segmented production affecting Cushing. Our production
                                                                      (3) the net additions to Cushing and storage utilization peak in
forecast builds the underpinning of all crude which will flow into
                                                                      1Q and 4Q, conversely with low crack spreads due to
Cushing. The basins are focused on the Canada oil sands and
                                                                      maximum turnarounds;
liquids rich shale plays that flow into Cushing (ex-Eagle Ford).
We forecast ~620kbd growth over the next 12 months and                (4) Cushing balances are flat in 3Q11;
~2,000kbd incremental growth over the next 5 years. Our
model is driven by: (1) play-by-play rig count forecast, (2)          (5) 2012 refinery turnarounds are historically heavy due to
drilling days, which drives monthly wells coming online, and (3)      scheduled maintenance, deferred 2011 turns and BP Whiting
mean type-wells for each play which are produce-out scenarios         being off-line for 5 months (7.5% of Mid-con crude run
considering IP, EUR and decline. We cumulate new wells                capacity);
brought online against declining existing wells on a monthly
basis, which shows an overall development program and                 (6) pipeline capacity into Cushing (inbound limitations) has
ultimate production forecast for each play.                           marginal negative impact in 2012 yet becomes more relevant in
                                                                      the 2014+ time frame;
We examined throughputs of all current and future
pipelines flowing into Cushing. For current pipelines, we             (7) Cushing fills again in 2015+ time as production growth
examined the potential to increase throughputs to take up             exceeds takeaway, yet too many variables could change the
incremental production from Canada and liquids rich shale             outcome so we don’t value this spread at this point,
plays into Cushing. We utilize existing capacity including spare
capacity in current pipelines to analyze how much crude oil           (8) 3 major lines expected to be build exiting Cushing in
production will actually get to Cushing and increase storage.         mid-2013 would have enough excess capacity for 12 months to
We believe initial inflows towards Cushing will be consumed by        deliver production growth and drain Cushing storage
                                                                      completely.



                                                                                                                                      8
                                                                                                          MORGAN              STANLEY          RESEARCH

                                                                                                          June 30, 2011
                                                                                                          Refining & Marketing




Exhibit 12
Morgan Stanley Cushing Balance Model
                                                                               2011                                  2012                                  2013
Incremental Crude Production into PADD II (mbpd)                  1Q11A    2Q11E      3Q11E    4Q11E    1Q12E    2Q12E      3Q12E    4Q12E    1Q13E    2Q13E      3Q13E    4Q13E    2014     2015     2016
   Canadian Oil Sands                                                30       30         30       30       48       48         48       48       31       31         31       31     169      101      123
   Bakken                                                            25       13         23       89       46       43         43       45       35       34         34       32     102       83       70
   Permian                                                           (2)       6         10        5        7        6          7        6        5        5          5        4      17       21       16
   Niobrara                                                           0       15         23       10        8        9          9        8        4        6          6        5      19       15       13
   Woodford                                                           2       10         23       12       11        8          7        5        3        4          5        4      15       15       12
   Q/Q Incremental Crude Oil Supply Growth                            55       74       110      147      120      114        114      112       78        80         80      76      322      235      234
   Total Incremental Crude Oil Supply Growth (mbpd)                   55     129        110      256      376      490        603      716      794      874        954     1,030   1,351    1,587    1,821

Pipeline Constraints Into Cushing (mbpd)
   Bakken/Canadian Spare Cushing Takeaway Capacity                  509     509        509      509      509      509        509      509      509      509         859      909    1,209    1,409    1,609
     Cumulative Production above Takeaway Capacity (constraint)       0       0          0        0        0        0         39      132      198      262           0        0        0        0        0
   Permian Spare Cushing Takeaway Capacity (mbpd)                    84      84         84       84       84       84         84       84       84       84          84       84      184      184      184
     Cumulative Production above Takeaway Capacity (constraint)       0       0          0        0        0        0          0        0        0        0           0        0        0        0        0
   Niobrara Spare Cushing Takeaway Capacity (mbpd)                   21      21         21       21       21       21         21      186      186      186         186      186      186      186      186
     Cumulative Production above Takeaway Capacity (constraint)       0       0         17       28       35       44         53        0        0        0           0        0        0        0        0
   Total Incremental Constraints to Production Growth                  0       0         17       28       35       44         92      132      198      262           0        0        0        0        0
   Q/Q Incremental Takeaway Constraints on Production Growth          0       0         17       10        8        9         48       40       66       64        (262)       0        0        0        0

   Total Incremental Net Cushing Production Growth (mbpd)            55      129         92      229      341      446        512      584      596      612        954     1,030   1,351    1,587    1,821
   Q/Q Incremental Net Cushing Crude Oil Supply Growth (mbpd)        55       74         92      136      112      105         66       72       13       16        342        76     322      235      234

Change in Refining Consumption in Mid-Con (mbpd)
  Cumulative Additional Mid-Con Refining Capacity                      0        0         0      130      130       130       130      215      245       245        347      347     347      347      347
  Incremental Mid-Con Refining Capacity                                0        0         0      130        0         0         0       85       30         0        102        0       0        0        0
  Total Mid-Con Refining Capacity                                  3,900    3,900     3,900    4,030    4,030     4,030     4,030    4,115    4,145     4,145      4,247    4,247   4,247    4,247    4,247

   Historic Refining Utilization (%)                                88%      90%        92%      88%      88%      91%        92%      88%      88%      91%        92%      88%     89%      89%      89%
   Estimated Mid-Con Turnarounds (mbpd)                              218       98         46       76      275      264        242      113       68      205         69       30     170      170      170
   Turnarounds % of Total Capacity                                 4.3%     1.9%       0.9%     1.5%     5.4%     5.2%       4.7%     2.2%     1.3%     4.0%       1.4%     0.6%    3.3%     3.3%     3.3%
   Est. Change in Utilization From Average (incl. Turnaround)        0%       2%         2%       3%       0%      -1%        -2%       2%      -2%       1%         0%       0%      0%       1%       2%
   Estimated Total Mid-Con Utilization (%)                          88%      92%        94%      91%      88%      90%        90%      90%      86%      92%        92%      88%     89%      90%      91%
   Q/Q Incremental Change in Mid-Con Crude Refining Consumpt          0      142         92      (11)    (122)      90          3       64     (140)     258         97     (182)     80       42       42
   Total Incremental Change in Refining Consumption                   0      142         92       81      (40)      49         53      117      (23)     236        333      150     230      272      315

Incremental Crude Pipeline Movement (mbpd)
   Longhorn Pipeline Reversal                                                                                                                    75      125         125      125     125      125      125
   Enbridge Line 9 Reversal                                                                                                                      60       60          60       60     200      200      300
   New Takeaway Pipeline: Keystone XL                                                                                                                                350      400     500      500      500
   New Takeaway Pipeline: Enbridge Monarch                                                                                                                 0         350      350     350      350      350
   New Takeaway Pipeline: Double E Pipeline                                                                                                     300      320         360      400     400      400      400
   Total Incremental Crude Oil Pipeline Capacity Out of Cushing                                                                                 435      505       1,245    1,335   1,575    1,575    1,675
   Q/Q Incremental Crude Pipeline Capacity Out of Cushing                                                                                       435       70         740       90     240        0      100

Incremental Crude Movement via High Cost Transport (mbpd)
   Total Rail Usage                                                 108      135        135      135      262      262        262      262      282      282        282      282      282      282      282
   Total Barge Usage                                                140      140        140      140      147      147        147      147      155      155        155      155      155      155      155
   Total Truck Usage                                                 15       15         15       15       15       15         15       15       15       15         15       15       15       15       15
   Total Incremental Rail, Barge, Truck Takeaway                    263      290        290      290      424      424        424      424      452      452        452      452      452      452      452
   Q/Q Incremental Rail, Barge, Truck Takeaway                       0       27          0        0      134        0          0        0       27        0          0        0        0        0        0

   Total Incremental Offset to Production Growth                    263     433        382      371      384      474        477      541      864     1,192      2,029    1,937    2,257    2,299    2,442
   Q/Q Change on Offset to Production Growth                          0     169         92      (11)      12       90          3       64      323       328        837      (92)     320       42      142

Storage at Cushing
   Added Storage Capacity (mbpd)                                      0       50         82       82       10       10          5        5        0        0          0        0        0        0        0
   Added Storage Capacity Total                                     0.0      4.5        7.4      7.4      0.9      0.9        0.5      0.5      0.0      0.0        0.0      0.0      0.0      0.0      0.0
   Cushing Storage Capacity Total Period End                       56.6     61.2       68.6     76.0     76.9     77.8       78.2     78.7     78.7     78.7       78.7     78.7     78.7     78.7     78.7

   Q/Q Incremental Crude Flow Into Cushing (mbpd)                    55      (96)         0      147     100        15         63        8     (310)    (313)      (495)     168        2      193       91
   Incremental Crude Flow Into Cushing (mmbbl)                      5.0     (8.6)       0.0     13.2      9.0      1.3        5.7      0.7    (27.9)   (28.2)     (44.5)    15.1      0.2     17.3      8.2
   Total Incremental Crude Flow Into Cushing (mmbbl)                5.0      0.0        0.0     13.3     22.2     23.6       29.2     29.9       2.1   (26.1)     (70.6)   (55.5)   (55.4)   (38.0)   (29.8)

   Ending Cushing Stocks (mmbbl)                                    41.8     38.0      38.0     51.3     73.5     97.1      126.4    156.3    158.3    132.2       61.6      6.1      0.0      0.0      0.0
   Cushing Storage Utilization                                      74%      62%        55%      68%      96%     125%       162%     199%     201%     168%        78%       8%       0%       0%       0%

   Shut-in Production (mmbbl)                                         0        0          0        0        0      19         48       78       80       54           0        0        0        0        0
   Shut-in Production (mbpd)                                          0        0          0        0        0     215        535      862      885      595           0        0        0        0        0

Source: Company data, Morgan Stanley Research estimates




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                                                                       Refining & Marketing




How We Forecast the WTI Differential
Trapped crude leads to discounted prices. We believe the               facilities), barge is best economics yet limited material growth,
US production growth trends and the latency in mid-stream              and truck is the most expensive and more theoretical then
logistics have and will continue to fundamentally change the           practically employed to physically evacuate crude from
pricing relationship between Mid-Con sourced/trapped crudes            Cushing (limited by trailer availability and backlog). We believe
and waterborne-priced crudes for the foreseeable future. This          $15/bbl is the level for incremental capacity while truck and
differential is characterized by WTI/LLS differentials, yet is         barge have the most sensitivity to materially attempting to
applicable to any crude that is influenced by logistic constraints     increase capacity (ie markets are thin and tight), meaning the
in the Mid-Con, with the primary bottleneck in Cushing,                more barrels moved in these methods the more price pressure
Oklahoma. Until 2011, this differential has been volatile,             to incremental costs.
largely oscillating around -$2 to +$2 spread. With unfettered
access in and out of the region, WTI is a marginally higher            Cushing storage economics relevant. As Cushing storage
quality crude to Brent and should be valued at a premium.              capacity grows beyond local regional, seasonal demand levels,
However, access to global markets (or lack thereof) is                 we believe storage economics – the differential required to buy,
everything in setting market prices, with US natural gas as the        hedge, store (~.45 a bbl per month) and ship crude with $4 tariff
most meaningful example of discounted prices following                 in 24-28 months to the Gulf Coast require ~$15 differential. As
trapped commodity supply.                                              barrels compete for storage as Cushing approaches full we
                                                                       believe this also supports our forecast.
We see several relevant price levels that drive our
fundamental valuation of the “spread” based on our                     We are introducing a $50+/bbl “bull case” spread for 4Q12,
analysis and conclusions on net Cushing balance: (1) the price         and believe there is reasonable probability the spread can
needed to physically move a barrel via pipeline from Cushing to        trade as wide as the price required to shut-in production (see
the Gulf Coast ($4/bbl); (2) the price needed to economically          following section). Our bull scenario is when capacity of barrels
clear the marginal barrels via “higher cost methods” of rail,          into Cushing exceed evacuation by all means and WTI price
barge or truck $10-14; (3) the differential required to sell           needs to force shut-in production – similar to the recent fall
forward LLS, buy, store, and ship barrels to the Gulf Coast in         ritual of full natural gas storage.
mid-late 2013 while earning a 20% return, ~$15/bbl; and (4) the
                                                                       Price required to shut-in production. Our bull scenario
price required to shut-in production, $50+/bbl.
                                                                       would be triggered by reaching the physical limits of Mid-Con’s
Price needed to physically move a barrel – post 2013                   ability to transport, process or store barrels, by any means.
differential. The lowest level, the tariff level, is based on          Barrels produced, by a large collection of independent E&Ps
incremental cost to move barrels out of Cushing via the two            and Majors may have to compete on price to a level that would
new proposed lines with 950 mbpd of capacity where we                  force some upstream operators to shut-in production or slow
estimate tariffs on Keystone XL, Monarch and Double E. We              growth. This is the classic prisoner’s dilemma we have
back into the differential, as Gulf Coast will get global parity       witnessed across the broader energy space through numerous
price (back out imports) so LLS price – transport = WTI price.         cycles from the first oil boom in 1850 in Pennsylvania, to East
We believe $4/bbl tariff will be the differential in 2H13 until 2015   Texas oil boom of the 1930s to more recent behaviors of US
when supply again exceeds takeaway capacity.                           E&P producers in natural gas markets. This large group of
                                                                       independent companies operating to maximize profit can
Price needed to economically clear the marginal barrels.               out-produce the sustainable price. The invisible hand will work
Our forecast of $15/bbl, is based on economic differential             at a price where both new development economic thresholds
required to move the last marginal barrel out of Cushing, OK           and full cycle cash costs become relevant. Based on a $120
via non-pipeline delivery (rail, barge, or truck). As pipeline         Brent price forecast, we believe a $50 differential is likely under
take-away capacity is constrained with no pipe-line exit from          new project development costs and $80 differentials is into
Cushing to the Gulf Coast until mid-2013, rail, barge and truck        cash costs on many projects. At those levels, we would expect
will need to employed or barrels will be left in the ground. All       someone to blink and bring production into manageable levels.
these methods are employed in various routes to move                   While not a long-term sustainable level those differentials
production in, around and out of the Mid-Con to either the             would be a boon to those refiners that sit on the toll road to
upper mid-west (Chicago, Capline market) or the Gulf Coast.            production growth – Mid-Con refiners.
Rail has longest lead-time (construction of transloading



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                                                                   June 30, 2011
                                                                   Refining & Marketing




Bull Case Scenario: Production Shut-in Scenario
We are introducing a $50+/bbl “bull case” spread for                Exhibit 13

4Q12, and believe there is reasonable probability the spread        Net Cushing Pressure
                                                                                                                                             Results of our Cushing                                                                                             (kbd)
can trade as wide as the price required to shut-in production                                                                                Balance Model - Takeaway
                                                                                 Alberta Bakken
(see above). Our bull scenario is when capacity of barrels into                  Mississippian Lime
                                                                                                         capacity is exceeded                                                                                                                                   7,000
Cushing exceed evacuation by all means and WTI price                             Woodford
                                                                                 Niobrara                                                                                                                                                                       6,000
needs to force shut-in production – similar to the recent fall                   Bakken
ritual of full natural gas storage.                                              Canada (ex. Oil Sands)                                                                                                                                                         5,000
                                                                                 Oil Sands (Mining & In-Situ)
                                                                                 Permian                                                                                                                                                                        4,000
Price required to shut-in production. Our bull scenario
would be triggered by reaching the physical limits of                                                                                                                                                                                                           3,000

Mid-Con’s ability to transport, process or store barrels, by any                                                                                                                                                                                                2,000
means. Barrels produced, by a large collection of
independent E&Ps and Majors may have to compete on price                                                                                                                                                                                                        1,000

to a level that would force some upstream operators to shut-in                                                                                                                                                                                                  0
production or slow growth. This is the classic prisoner’s            2000              2002                 2004                    2006               2008                   2010                  2012                2014                     2016
dilemma we have witnessed across the broader energy space
                                                                    Source: Company data, Morgan Stanley Research estimates
through numerous cycles from the first oil boom in 1850 in
Pennsylvania, to East Texas oil boom of the 1930s to more           Full Cushing storage also drives contango benefit. As
recent behaviors of US E&P producers in natural gas markets.        Cushing storage fills, we would expect WTI time spreads
This large group of independent companies operating to              (front month contango) to widen, as barrels bid for limited
maximize profit can out-produce the sustainable price. The          storage. We would expect to see steeper contango in
invisible hand will work at a price where both new                  following 2Q 12, when Cushing approaches or exceeds full
development economic thresholds and full cycle cash costs           storage.
become relevant. Based on a $120 Brent price forecast, we
believe a $50 differential is likely under new project              Exhibit 14
development costs and $80 differentials is into cash costs on       Time Spreads Will Provide Contango Benefits
many projects. At those levels, we would expect someone to                   $4.00                                                                                       WTI                        Brent
blink and bring production into manageable levels. While not
a long-term sustainable level, those differentials would be a                $2.00

boon to those refiners that sit on the toll road to production               $0.00
growth – Mid-Con refiners.
                                                                     $/bbl




                                                                             ($2.00)

Cushing Storage Levels are the Bottom Line Indicator.                        ($4.00)
We believe Cushing balance is the bottom line of our new
                                                                             ($6.00)
Mid-Con model. We believe if crude cannot get off the
“Mid-Con island” or get stored in Cushing, production must get               ($8.00)
                                                                                       Jul-06
                                                                                                Oct-06
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                                                                                                                           Jul-07
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                                                                                                                                                                                                                                                           Jan-11
                                                                                                                                                                                                                                                                    Apr-11




shut-in or go into tertiary storage. We believe full Cushing
defines a new level for the Mid-Con differential, our bull case,
versus the $18-20/bbl, which we believe is supported by             Source: Bloomberg, Morgan Stanley Research

storage and transport economics. The stocks, the earnings
estimates, nor the forward commodity curve do not price in our
bull case scenario. Currently, the forward curve is                 Contango benefit winners FTO, HOC, TSO, WNR, DK,
backwardated in out years and does not price in materially          MPC (more modest VLO). Refiners will also benefit from the
wider spreads, let alone a continuation of current spreads          contango based on contract monthly average (CMA) pricing
through mid-2013.                                                   and WTI price discounts. For refiners, this can add an
                                                                    additional $1-2 per barrel on the gross margin based upon the
                                                                    historical term structures of WTI when Cushing fills. We
                                                                    expect contango benefits will appear more following 2Q12.




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                                                                  June 30, 2011
                                                                  Refining & Marketing




The contango benefit occurs as refiners engage in a series of      Onshore Natural Gas Analogy
paper hedges to better match the timing of crude orders and
crude deliveries. When a company enters into crude                 The US natural gas market became fundamentally
purchases (often 20th day of the month), it sells the second       oversupplied beginning in the 2nd half of 2009 and continued
and third month forward contracts (2/3, 1/3 generally), locking    through 2010 due to production growth driven primarily by
in the structural benefit/discount of the curve. Each day crude    horizontal drilling across unconventional onshore plays. A
is run, the refiner covers an equal portion of the hedged          confluence of factors incented producers to continue to grow
amount which allows it to better match current crude and           production even in the face of oversupplying the market.
product pricing (revenues and costs). When the WTI is in           Producers’ development decisions were distorted by: (1)
contango, the refiner picks up the difference between front        hedging, (2) joint-ventures, (3) NGL production, and (4) held
month and the next two months (as it buys spot and selling         by production lease terms. Compounding this was a strong
higher priced forward contracts: the opposite holds true if the    contango in the forward curve, producers made development
curve is backwardated). Refiners who benefit from CMA              outlays based on projected economics using “strip pricing.”
pricing include FTO, HOC, TSO, WNR, MPC, DK and ALJ.               Eventually, the compression of the long dated contracts
We also note that CMA pricing is less for VLO, which receives      (selling the back of the curve) acts to support the market as it
benefits on a smaller portion of refining capacity, including      reduces the price level for hedging, reduces the incentive to
Ardmore and McKee refineries.                                      shut-in, and reduces the incentive to hold back well
                                                                   completions. The combination of these factors shaped drilling
                                                                   behavior even as the 12-month strip declined, causing
                                                                   significant oversupply.

                                                                   The natural gas market oversupply is analogous to the growth
                                                                   in onshore unconventional oil plays. The advances in
                                                                   unconventional natural gas field development are being
                                                                   utilized in oil rich plays across the U.S., similar to natural gas.
                                                                   Just as natural gas producers faced economic incentives to
                                                                   continue to produce, similar distortions will arise in the crude
                                                                   market, supported by contango in the forward curve. Just as
                                                                   gas producers hedged, entered into joint ventures, and drilled
                                                                   under lease terms, oil producers are faced with the same
                                                                   incentives. Unconventional oil producers are hedging, locking
                                                                   in today’s curve, entering into joint-ventures and drilling to
                                                                   hold acreage rather than see the leases expire. The back of
                                                                   the curve is being sold forcing downward pricing pressure,
                                                                   producers will eventually be forced to reduce their drilling
                                                                   outlays, and in turn, production.




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                                                                                    June 30, 2011
                                                                                    Refining & Marketing




Production Growth and Take-Away Summary
We built a play-by-play model, which forecasts production                           Exhibit 15

growth across North America onshore, we then                                        North American Onshore Production Forecast
segmented production affecting Cushing. Our forecast is                                                                                                                (kbd)
                                                                                             Alberta Bakken
for ~620kbd growth over the next 12 months and 2,000kbd                                      Mississippian/Utica/Monterey
                                                                                                                                                                       7,000

incremental growth over the next 5 years. Our model is driven                                Woodford
                                                                                             Niobrara                                                                  6,000
by: (1) play by play rig count forecast, (2) drilling days, which                            Eagle Ford
                                                                                             Bakken                                                                    5,000
drives monthly wells coming online, and (3) mean type-wells for                              Canada (ex. Oil Sands)
each play which are produce-out scenarios considering IP,                                    Oil Sands (Mining & In-Situ)                                              4,000
                                                                                             Permian
EUR and decline. We cumulate the wells being brought online                                                                                                            3,000
against declining existing wells on a monthly basis which
                                                                                                                                                                       2,000
shows an overall development program and ultimate
production forecast for each play.                                                                                                                                     1,000

                                                                                                                                                                       0
We forecast the majority of Cushing-affected growth from                              2000        2002    2004        2006    2008   2010      2012     2014    2016
the Bakken and Canada (Oil Sands) with moderate growth                              Source: Company data, Morgan Stanley Research estimates
estimates coming from the Permian, Mid-Con plays, and
the Niobrara. Our Bakken forecast uses a mean type well                             Exhibit 16

considering IPs and EURs from the Sanish, Three Forks, East                         Production Forecast Affecting Cushing
Nesson, and West Williston areas of the greater Williston Basin.                                                                                                       (kbd)
                                                                                             Alberta Bakken
Our rig count forecast in the Bakken grows to 189 from 138                                   Mississippian Lime                                                        6,000
                                                                                             Woodford
through 2012 which is slightly lower than a 200 rig count recent                             Niobrara
                                                                                                                                                                       5,000
company presentations/forecasts have predicted. We see the                                   Bakken
                                                                                             Canada (ex. Oil Sands)
rig count forecast as bringing on ~100 wells/month pro forma                                 Oil Sands (Mining & In-Situ)                                              4,000
which we see building production another ~124kbd over the                                    Permian

next year and ~650kbd over the next 5 years. Canadian                                                                                                                  3,000

production growth, which utilizes CAPP’s recently released
                                                                                                                                                                       2,000
forecast is expected to increase significantly from the oil sands.
CAPP’s oil sands production growth forecast is for over 100kbd                                                                                                         1,000
this year and ~700kbd over the next 5 years.
                                                                                                                                                                       0
                                                                                      2000        2002    2004         2006   2008    2010     2012     2014    2016

                                                                                    Source: Company data, Morgan Stanley Research estimates



Exhibit 17
Emerging Liquids Plays Model Summary Assumptions & Output

                                                                                                             1-Year                5-Year
                                                                        Existing                           Cumulative            Cumulative
                                                  Average Rig Count    Production        Drilling          Production            Production           5-Year CAGR
                                                  2011          2012      (kbd)           Days             Added (kbd)           Added (kbd)           Production
             Permian (Hz. Rigs)                    42           52        875                30                  21                  111                39.8%
             Woodford (Anadarko)                   32           35         3                 30                  45                  127                22.9%
             Mississippian Lime                    19           21         6                 20                  35                   79                17.6%
             Bakken                               145           171       341                40                  124                 650                39.2%
             Niobrara DJ Basin                     35           48        53                 30                  48                  143                24.2%
             Alberta Bakken                        1             6         0                 30                   1                   16                65.8%
             Canada (Western Sed. Basin)          365           433      1,082               -                   16                   21                 5.6%
             Oil Sands                             NA           NA       1,470               -                   106                 686                45.4%
             Total/Avg.                            67           87       3,980               19                  698                 2,766              79.2%
Source: Company data, Morgan Stanley Research estimates




                                                                                                                                                                           13
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                                                                                              June 30, 2011
                                                                                              Refining & Marketing




Canadian Oil Sands
Western Canada oil production is set to grow over 600 mbpd                                    South on the Lakehead, Express, Alberta Clipper and
for the next 4 years with almost all volumes moving                                           Keystone pipelines or West via Trans Mountain pipeline. The
into/through the US Mid-Con. Canadian oil production growth                                   infrastructure supports current and future Canadian production
acts as the backbone of crude growth and logistical constraints                               in Canada, but fails to move barrels past Cushing, OK until
into US Mid-Con. The Canadian Associations of Petroleum                                       mid-2013.
Producers (“CAPP”) increased their annual production forecast
in June by ~180 mbpd for the 2015 period, which is our base                                   Platte Pipeline system downstream of Express pipeline, has
case, and, additional unconventional production in emerging                                   been filled with growing Bakken volumes and kept Express line
tight oil plays could provide another source of upside to our                                 at 200kbpd of 280kbpd of capacity. With ultimate goal to get
estimates in 2013-2015+ period.                                                               significant volumes to the Gulf Coast, which has ~9 mmbpd of
                                                                                              refining capacity including significant coking capacity,
                                                                                              Canadian crude deliveries into Cushing and the Mid-Con will
Canadian production growth fills the top of the pipeline
                                                                                              be held up until major lines are completed to the coast.
system. We forecast Canadian oil production (ex offshore
                                                                                              Keystone XL will help relieve pressure in the crude bottleneck,
Atlantic) will ratably grow an incremental 700kbpd over the next
                                                                                              and will provide a direct passage from Hardisty to Houston by
5 years. The Canadian oil sands will add ~150kbpd for each of
                                                                                              mid-2013, with longer-term solutions (2015+) from Northern
the next five years from SAGD, CSS and mining operations.
                                                                                              Gateway and Northern Leg to Kitamat on the West Coast.
Major projects driving oil sands volumes include Imperial’s
Kearl Lake (4Q 2012 ramp of Phase 1) and expansions by both                                   Exhibit 19
Syncrude (2012) and CNRL’s Horizon (2012, Phase 2 and 3                                       Canadian Pipelines: Current and Future
expansion). Unlike many US tight oil plays, the Canadian                                      Current
                                                                                                                                                                        Nameplate Heavy Light
producers are at the top of the primary pipeline systems, yet                                  Operator        Origin         Destination            Name                 Capacity        Mix
Canadian volumes are still subject to downstream limitations,                                 Enbridge         Hardisty, AB   Chicago and Montreal   Lakehead System        1,865     (60/40)
                                                                                              Kinder Morgan    Hardisty, AB   MT, WY, UT and CO      Express                  280     (65/35)
including limited pipeline takeaway capacity.                                                 Enbridge         Hardisty, AB   Clearbrook, MN         Alberta Clipper          450     (100/0)
                                                                                              TransCanada      Hardisty, AB   Patoka, IL             Keystone                 591     (75/25)
                                                                                              Kinder Morgan    Hardisty, AB   Vancouver              Trans Mountain           300     (20/80)
Exhibit 18
                                                                                              Total                                                                         3,486
Western Canadian Oil Production Forecast
                                                                                              Future Planned
        4,000     Conventional Light   Oil Sands   Conventional Heavy   Pentanes/Condensate
                                                                                                                                                                        Nameplate   Expected
                                                                                               Operator        Origin         Destination            Name                 Capacity Completion
        3,500                                                                                 TransCanada      Hardisty, AB   Houston, TX            Keystone XL              500       2013
                                                                                              Enbridge         Bruderheim     Kitamat, BC            Northern Gateway         525       2016
        3,000                                                                                 BP               Edmonton, AB   Kitamat, BC            Northern Leg             400       2016
                                                                                              Kinder Morgan    Edmonton, AB   Kamloops, BC           TMPL2                     80       2016
        2,500                                                                                 Kinder Morgan    Kamloops, BC   Sumas, BC              TMPL3                    320       2016
                                                                                              Total                                                                         1,825
 mbpd




        2,000                                                                                 Source: Company data, Morgan Stanley Research

        1,500
                                                                                              Additional potential production. The Western Canadian
        1,000
                                                                                              Sedimentary Basin contains the 3rd largest reserves of oil, is
         500                                                                                  over 540,000 square miles and underlies many of the
                                                                                              Canadian provinces including; Alberta, Saskatchewan, British
           0
                2010        2011E      2012E       2013E       2014E     2015E       2016E    Columbia, and Manitoba. While conventional fields are
Source: CAPP, Morgan Stanley Research estimates
                                                                                              relatively mature, by drilling horizontal wells with multi-stage
                                                                                              fracs in conventional reservoirs has led to the reversal of
Five major ways out of Canada via pipeline. Canada                                            declines and the most recent land grab and series of highly
currently has over ~3.4mmbpd of pipeline capacity that meets                                  watched emerging tight oil plays indicates potential upside to
all of the oil sands and conventional Canadian production                                     our estimates. While still early days, we believe it is reasonable
growth into the US. The existing pipeline architecture was                                    to assume some of the geology that has developed into
designed in connection with upstream growth to move                                           significant production adds in the US will be discovered and
Canadian crudes south. Canada's pipeline infrastructure is                                    developed in Canada.
primarily composed of 5 major pipelines that move crude either



                                                                                                                                                                                        14
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                                                                         June 30, 2011
                                                                         Refining & Marketing




Bakken
                                                                         Exhibit 21
Williston Basin production has the potential to grow to over 1
mmbpd over the next 5 years. Currently at ~340 kbd with ~140             Bakken Recoverable Resource Potential
                                                                                                                                                                                                                                 Bakken (ND
rigs running, most industry forecasts call for the rig count to                                                                                                                                                                       & MT) Three Forks
grow to 200 within the next 12-24 months all driven by a
                                                                         Aereal Extent (Sq. Miles)                                                                                                                                           14,700                                    14,700
combination of the right geological factors, which make the
                                                                         Acerage                                                                                                                                                    9,408,000                                9,408,000
Basin’s wells economic in lower pricing environments.
                                                                         Fluid Type                                                                                                                                                                          Oil                                     Oil
                                                                         OOIP / Sq. Mile                                                                                                                                                      8,120                                         8,120
Bakken growth to ~700kbd in the next 5 years and
                                                                         Recovery Factor                                                                                                                                                        2.0%                                        1.5%
logistically constrained due to lack of infrastructure. With
                                                                         Spacing (on 1280)                                                                                                                                                                   4                                                   4
the potential for 700kbd of incremental production coming
                                                                         Total Recovered / Sq. Mile (mboe)                                                                                                                                           650                                     487
online in the next 5 years, upstream producers will be focused
                                                                         Total Recoverable (Mmboe)                                                                                                                                            9,549                                         7,162
on ways to transport crude out of the Bakken and into the
Cushing and Gulf Coast markets. Current production is                    Peak Production (mboepd)                                                                                                                                             1,000                                         1,000
~340kbd and many major producers have established                        R/P                                                                                                                                                                                 26                                20
positions in the play including, within our coverage, HES, MRO,          Source: Continental Resources, USGS, Morgan Stanley Research

COP with smaller cap names like CLR, WLL, BEXP, and OAS
also with significant positions.
                                                                         Williston Basin prospectivity is generally regarded as economic
Exhibit 20                                                               even under stress case pricing scenarios, with Sanish
Bakken Acreage Positions                                                 breakeven pricing at $40/bbl, and Three Forks at $62/bbl. In
               Majors                              Small-Mid             our view, the Bakken will continue to see activity for the
HES                          900,000        CLR                868,900
COP                          460,000        WLL                600,000   foreseeable future, the question remaining is how fast will it
XOM                          410,000        EOG                600,000   grow?
MRO                          391,000        OAS                303,000
OXY                          200,000        DNR                266,000
                                                                         Exhibit 22
                                            BEXP               224,400
                                            ERF                119,500   Bakken Wells are Economic Below $65/bbl (# too
                                            KOG                 70,000   small in chart
Source: Company data, Morgan Stanley Research                            80
                                                                                                 Required Strip for 10% IRR




                                                                                                                                                                                                                                                                                              67
                                                                         70




                                                                                                                                                                                                                                                                  62


                                                                                                                                                                                                                                                                              62
Estimates of recoverable resource vary from Continental’s 24
                                                                                                                                                                                                                                                 58
                                                                                                                                                                                                                                   57

                                                                         60
                                                                                                                                                                                                     55


                                                                                                                                                                                                                 55
                                                                                                                                                                               54




Bbbls to the USGS at 9 Bbbls. We use released company and
                                                                                                                                                 51


                                                                                                                                                                51




                                                                         50
                                                                                                                                   45
                                                                                                                    44




agency data within the play (mean OOIP/section of
                                                                                                       42
                                                                               40




                                                                         40
~8.1mmboe, mean recovery factor) to determine a ~17mmboe
                                                                         30
recoverable resource estimate.
                                                                         20


                                                                         10


                                                                          0
                                                                                                                                                            Permian - Spbrry
                                                                                                     Permian -



                                                                                                                 (Horizontal)
                                                                               Bakken (Sanish)




                                                                                                                                                                                                  Bakken (West




                                                                                                                                                                                                                                              (Condensate)

                                                                                                                                                                                                                                                              Bakken (East




                                                                                                                                                                                                                                                                                              Eagle Ford (Oil)
                                                                                                                 Carbonates


                                                                                                                                Permian - Bone




                                                                                                                                                                                                                                 Wolfcamp
                                                                                                                                                 Niobrara




                                                                                                                                                                               Permian - Avalon




                                                                                                                                                                                                                 Mississippian




                                                                                                                                                                                                                                                                              Three Forks
                                                                                                     Wolfberry




                                                                                                                                                                                                                                 Permian -


                                                                                                                                                                                                                                               Eagle Ford
                                                                                                                                                                                                    Williston)




                                                                                                                                                                                                                                                                Nesson)
                                                                                                                                                              (110 mboe)
                                                                                                                                    Spring




                                                                         Source: Company data, Morgan Stanley Research


                                                                         We forecast ~300kbd growth over next 18-months. Our
                                                                         Production forecast is built using three publicly available
                                                                         inputs: (1) Historical rig count data (Land Rig Newsletter), (2)
                                                                         Basin type well, using company released IP, EUR and decline
                                                                         curve metrics, and (3) Drilling Days generally announced via
                                                                         company presentations and conference calls. From these
                                                                         inputs we derive a cumulative estimate of wells brought online



                                                                                                                                                                                                                                                                                              15
                                                                                              MORGAN              STANLEY               RESEARCH

                                                                                              June 30, 2011
                                                                                              Refining & Marketing




and thus estimate total production added, additive to the                                     Out of the Bakken not a problem, but getting out of
existing production stream which is subject to a decline factor.                              Cushing is. In our opinion, current Bakken production is able
We back check our forecast against individual company                                         to move South to Cushing via major pipelines that include:
provided growth forecasts.                                                                    Keystone, Enbridge Mainline & Lakehead system, Alberta
                                                                                              Clipper hence there is no imminent threat of upstream
Exhibit 23                                                                                    producers shutting in production. However, the major lines that
Bakken Production Build                                                                       may move up to 2mmbpd of crude are constrained once they
                                 2Q11     3Q11     4Q11   1Q12      2Q12     3Q12      4Q12   reach their final destinations of either Cushing or Patoka.
Rig Count                         138     145       151    160       169      179       189   Cushing is the ultimate bottleneck in the system and Patoka
 Growth %                                5.1%     4.1%    6.0%     5.6%      5.9%      5.6%   only exacerbates this problem as Spearhead flows its overflow
Existing Production (Declined)    335     319       303    288       274      261       248   into Cushing, hence the need for additional evacuation
Cum'l. Production Added (kbd)      13      36       124    171       214      256       302
                                                                                              capacity needs to be constructed to move crude out of Cushing
End Total Production (kbd)        354     360       433    464       492      521       554
                                         1.8%     20.2%   7.2%      6.1%     5.9%      6.2%
                                                                                              and into the Gulf Coast.
Source: Company data, Morgan Stanley Research estimates
                                                                                              Exhibit 25
                                                                                              Production vs. Takeaway (Pipeline & Rail) Capacity
Moderate rig build adds +20% sequential growth. Our
model uses a moderate rig count growth rate moving from 138                                     1,400
to 189 and then constant by the end of next year. We see this                                                     Daily Production (kbd)
                                                                                                1,200
as sustainable as the Bakken is relatively de-risked, has large                                                   Take-Away (kbd)

undeveloped tracts remaining, and is economic at sub $70 oil,                                   1,000

this combination makes it unlikely the rig count will fall below                                  800
current levels. Even reducing our rig count to 150, cumulative
                                                                                                  600
production growth remains above 15% through 2013. Our
forecast, which we believe is relatively conservative, adds                                       400
300kbd through 2012 and 440kbd through 2013.
                                                                                                  200

Exhibit 24                                                                                          0
Bakken Pipeline & Rail Transportation                                                                      Jun-   Sep-   Dec-    Mar-      Jun-   Sep-   Dec-   Mar-   Jun-   Sep-   Dec-
                                                                                                            11     11     11      12        12     12     12     13     13     13     13
Pipeline (kbd)                             2010        2011          2012           2013
KM Express (Platte)                     280,000     280,000       280,000        280,000      Source: Company data, Morgan Stanley Research estimates
Butte Pipeline                          118,000     118,000       150,000        150,000
Enbridge North Dakota                   161,500     161,500       161,500        161,500
Tesoro Mandan Refinery                   58,000      58,000        63,000         68,000
Enbridge Sweet Only                                  23,500        23,500         23,500
Enbridge Bakken Expansion                            25,000        25,000        145,000      Rail is a solution to move crude past Cushing and Patoka.
Butte Pipeline Expansion                             32,000        32,000         32,000      One solution of bypassing the Cushing bottleneck that Bakken
Butte Loop (Belle Fourche Loop)                                    50,000         50,000
Plains Bakken North                                                50,000         50,000      producers are using is rail. Unit trains are currently being used
Keystone XL Interconnect                                                         100,000      by EOG who moves ~40-50kbpd of crude and Hess will move
Total Pipeline                          617,500     698,000       835,000      1,060,000
                                                                                              120kbpd once its Tioga terminal is completed in 2012. We see
Rail (kbd)
Various Sites including                  30,000       30,000       30,000            30,000   an 18-month lead time, limiting material rail expansion in front
EOG Rail                                 65,000       65,000       65,000            65,000   of new outbound Cushing pipelines, expected in 2013
Dakota Transport Solutions               20,000       40,000       40,000            40,000
Hess Rail                                                          60,000            60,000
Rangeland COLT Hub                                                 27,000            27,000
Total Rail                              115,000     135,000       222,000           222,000
TOTAL                                   732,500     833,000      1,057,000     1,282,000
Source: Company data, Morgan Stanley Research estimates




                                                                                                                                                                                      16
                                                                  MORGAN              STANLEY               RESEARCH

                                                                  June 30, 2011
                                                                  Refining & Marketing




Permian Basin
                                                                  Exhibit 26
The Permian Basin is experiencing renewed focus as
commodity prices have increased activity and the application of   Acreage Holders
horizontal development programs applied to traditional vertical                   Large Caps                                       Small-Mid Caps
                                                                  APA                              3,000,000          XEC                                448,000
carbonate targets (Wolfcamp) as well as shale intervals
                                                                  OXY                              2,400,000          CXO                                374,523
(Avalon). While current production is ~875kbd, we forecast        XOM                              2,156,000          HK                                 325,000
total production to exceed 900kbd in the next 12 months and       CVX                              1,130,000          AREX                               134,500
930kbd in the next 24 months.                                     COP                              1,040,000          PXD                                125,000
                                                                  CHK                               670,000           EGN                                 80,360
                                                                  DVN                               455,000
Permian production increasing and incremental growth              APC                               330,000
clears through the Cushing market. We believe that                EOG                               120,000
Permian Basin crude production will rise an incremental           Source: Company data, Morgan Stanley Research
~50kbpd by 2012 and that there will be enough pipeline
                                                                  Exhibit 27
capacity to move the growing production to Cushing. Crude         Permian Recoverable Resource Potential
will move via OXY’s Centurion North pipeline and Basin (who is
                                                                                                                                                   Permian
expanding an additional 50kbpd) or by West Texas Gulf             Aereal Extent (Sq. Miles)                                                          8,400
moving crude south to Nederland. Potential additional             Acerage                                                                        5,376,000
takeaway capacity is the reversal of Magellan’s Longhorn          Fluid Type                                                                            Oil
                                                                  Total Recoverable (Mmboe)                                                         45,000
pipeline (currently Houston to El Paso) which would add
                                                                  Peak Production (mboepd)                                                           2,000
another 75kbd out of the Permian (Crane, TX to Houston),          R/P                                                                                   62
expanding to 125kbd in 2H 2013. The Permian is a unique           Source: USGS, Texas Railroad Commission, Morgan Stanley Research
combination of conventional production, EOR production, and
new and emerging unconventional type oil plays. This              We focus on unconventional rig count growth increasing
combination results in less basin-specific data and makes         from 40 to 55 through 2012. The current rig count in the
Permian production growth forecasts challenging, hence, our       Permian Basin is ~455 rigs with ~40 horizontal rigs running.
conclusions are likely conservative. Major upstream producers     Even though there will be an increase in production due to an
like OXY, APA, DVN, PXD and CHK are using unconventional          increase in vertical well programs (SD, WTI, APC, PXD) we
drilling techniques across their new or existing acreage to       conservatively model growth in that production stream as
increase oil production an incremental 100kbpd by 2015.           maintaining current production. The incremental production
Permian producers will likely continue to realize lower crude     growth, in our view, will come from horizontal drilling targeting
prices as Cushing remains logistically constrained.               the Bone Spring, Avalon, Wolfberry, Spraberry, and Wolfcamp
                                                                  formations which we forecast at a moderate growth rate of ~1%
Our Permian forecast is for production growth to come             through 2012.
from unconventional targets. While there is an increase in
vertical development programs across the play as well as          Exhibit 28
increased EOR activity, we conservatively forecast this as        Permian Production Build
maintaining current production levels, ~875kbd. We focus                                             2Q11      3Q11    4Q11       1Q12   2Q12    3Q12       4Q12

instead on the basin’s unconventional targets in the Midland      Rig Count                            40        40         45      50     50       55        55
                                                                   Growth %                                    0.0%   12.5%      11.1%   0.0%   10.0%       0.0%
and Delaware basins where more significant incremental
                                                                  Existing Production (Declined)      875       875        875     875    875     875        875
production growth is expected to be generated.                    Cum'l. Production Added (kbd)         6        15        21       27     34       40        46
                                                                  End Total Production (kbd)          881       890        896     902    909     915        921

                                                                  Source: Company data, Morgan Stanley Research


                                                                  In our view, the repeatability of a horizontal program across the
                                                                  various intervals and the optimal parts of the play for
                                                                  multi-stage frac wells is yet to be determined (or publicly
                                                                  available). A rig count moving to 75-80 rigs could be justified as
                                                                  large producers (APA, DVN, XEC) have focused their onshore




                                                                                                                                                             17
                                                                     MORGAN                                      STANLEY                                              RESEARCH

                                                                     June 30, 2011
                                                                     Refining & Marketing




development programs in the basin, however, we have not              Bone Spring in the Northern and Southern Delaware Basin
included that case.                                                  (New Mexico & Texas). The second Bone Spring located in
                                                                     the Northern Delaware basin, appears productive, with
Developing the Midland and Delaware basins will drive                carbonate sections as secondary targets. Horizontal drilling is
incremental growth. There are several development                    targeting the third Bone Spring in Texas (Southern Delaware
scenarios occurring across the play as producers bring               Basin), this interval is positioned directly on top of the
horizontal drilling to the Wolfcamp, Spraberry and Avalon            Wolfcamp at 10-11.5k ft depth and is composed of sand mixed
Shale as well as targeting stacked intervals with vertical wells.    with shales, and is over-pressured as compared to the 2nd
Typically, Midland basin producers drill vertical wells through      Bone Spring targets on the shelf.
several different pay zones, horizontal drilling (which drives our
incremental production forecast) is most likely to be focused in     Spraberry/Wolfcamp Midland Basin. The Wolfberry
the Delaware Basin. The Wolfcamp formation within the                (Midland Basin) is the name attributed to the comingled
Delaware basin is over-pressured relative to the Midland side,       production from the Wolfcamp through Spraberry formations,
with geology more encouraging for horizontal play concepts.          the Spraberry was first developed in the 1950’s (sandstones,
AREX announced the completion of a Wolfcamp horizontal               siltstones interbedded with limestones and shales) and was the
well with a +300kbd IP, but withheld more complete results for       primary target for most producers in the basin from the 1950’s
its 2Q11 earnings discussion.                                        to the 1980’s. PXD has been active in the play, and recently
                                                                     increased the expected EUR to 140 mboe.
Avalon Shale (Delaware Basin): The Avalon Shale is an
unconventional play which is being targeted with wells at            Exhibit 30

5.5-6.5k ft depth. The oil-to-gas mix transitions East-to-West in    Permian wells are economic in a low pricing
the play, with increasing liquids content in the Eastern part of     environment
                                                                     80
the play. CHK has been one of the early producers in the area,                              Required Strip for 10% IRR




                                                                                                                                                                                                                                                                                    67
with a number of 1,000+ boe/d IP rate wells, including the Ross      70




                                                                                                                                                                                                                                                          62


                                                                                                                                                                                                                                                                      62
                                                                                                                                                                                                                                           58
Ranch 6 Federal 1H at 1,528 boe/d. DVN is also active here,




                                                                                                                                                                                                                              57
                                                                     60




                                                                                                                                                                                                55


                                                                                                                                                                                                            55
                                                                                                                                                                          54
                                                                                                                                            51


                                                                                                                                                           51
with 4 rigs running. DVN expects EURs in the 400-600 mboe            50
                                                                                                                              45
                                                                                                               44
                                                                                                  42




range for the play.
                                                                          40




                                                                     40


                                                                     30
Exhibit 29
                                                                     20
Emerging Plays in the Permian
                                                                     10


                                                                      0
                                                                                                                                                       Permian - Spbrry
                                                                                                Permian -



                                                                                                            (Horizontal)
                                                                          Bakken (Sanish)




                                                                                                                                                                                             Bakken (West




                                                                                                                                                                                                                            Wolfcamp


                                                                                                                                                                                                                                        (Condensate)

                                                                                                                                                                                                                                                       Bakken (East




                                                                                                                                                                                                                                                                                    Eagle Ford (Oil)
                                                                                                            Carbonates


                                                                                                                           Permian - Bone



                                                                                                                                            Niobrara




                                                                                                                                                                          Permian - Avalon




                                                                                                                                                                                                            Mississippian




                                                                                                                                                                                                                                                                      Three Forks
                                                                                                Wolfberry




                                                                                                                                                                                                                            Permian -


                                                                                                                                                                                                                                         Eagle Ford
                                                                                                                                                                                               Williston)




                                                                                                                                                                                                                                                         Nesson)
                                                                                                                                                         (110 mboe)
                                                                                                                               Spring




                                                                     Source: Company data, Morgan Stanley Research


                                                                     Permian dynamics, the who, what, where, and how
                                                                     Permian crude gets to market. The Permian has three main
                                                                     pipelines SUN’s West Texas Gulf (WTG), PAA’s Basin and
                                                                     OXY’s Centurion that have nearly ~1mmbpd of capacity that
                                                                     moves crude to Cushing and Nederland, TX. Basin and
                                                                     Centurion move crude to Cushing while WTG move crude to
                                                                     Nederland where it can link to the SUN’s Mid Valley pipeline
                                                                     that moves crude further northeast to the Ohio Valley.

Source: Concho, Morgan Stanley Research




                                                                                                                                                                                                                                                                                    18
                                                                                                    MORGAN              STANLEY               RESEARCH

                                                                                                    June 30, 2011
                                                                                                    Refining & Marketing




Exhibit 31                                                                                          Exhibit 32
Permian Basin Crude Pipelines (2011 data)                                                           Permian Production vs. Takeaway Capacity
Current
                                                                        Nameplate                     1,600
Opeartor         Origin           Destination   Name                     Capacity     Utilization
Plains           Permian          Cushing       Basin                     400,000            86%
                                                                                                      1,400             Daily Production (kbd)
Occidental       Permian          Cushing       Centurion North           350,000            17%                        Throughput (kbd)
Sunoco           Permian          Nederland     West Texas Gulf           300,000            90%
                                                                                                      1,200
Sunoco           Permian/Eagle FoToledo         Mid Valley                238,000            88%
Total            Total                                                   1,288,000           68%
                                                                                                      1,000

                                                                                                        800
Future Planned

Opeartor         Additional future capacity     Name              Capacity Addition   Time frame        600
Sunoco           Permian          Nederland     West Texas Gulf           100,000     18 months
Magellan         Permian          Houston       Longhorn            75,000-125,000 18-24 months         400

Source: Company data, Morgan Stanley Research                                                           200

                                                                                                          0
Two of the three majors pipes are close to full capacity with: 1)                                                Jun-   Sep-   Dec-    Mar-      Jun-   Sep-   Dec-   Mar-   Jun-   Sep-   Dec-
SUN’s West Texas Gulf (nameplate 300kbpd) is currently 90%                                                        11     11     11      12        12     12     12     13     13     13     13

utilized and 2) PAA’s Basin pipeline (nameplate 400kbpd) is                                         Source: Company data, Morgan Stanley Research
86% utilized. Both of these pipelines are nearly at full capacity
and SUN has recently announced plans to increase capacity at
West Texas Gulf by more than 33% or 100kbpd in 18 months                                            In the near term, this leaves only one major pipeline,
and Basin plans to increase capacity by 50kbpd to meet                                              Centurion, open for increased flows. According to our
greater Permian capacity demand. A decision by Magellan on                                          estimates the Centurion pipeline has only averaged 55kbpd of
reversal of the Longhorn pipeline is expected within the next                                       crude flow or 60% utilization for the last 12 months. There is
month. The reversal would bring 75kbd, likely expanding                                             35-125kbpd of spare capacity to move incremental Permian
beyond initial capacity, to Houston and would be operational                                        crude production through the pipe but the only issue is that it
within 18-24 months.                                                                                will have to compete with Bakken and Canadian crude flows
                                                                                                    into Cushing.




                                                                                                                                                                                            19
                                                                                  MORGAN                                       STANLEY                                               RESEARCH

                                                                                  June 30, 2011
                                                                                  Refining & Marketing




Niobrara
The Niobrara horizon has garnered industry attention over the                     Further delineation coming in 2Q. Two farm-outs and
last 24 months with producers leasing up the play outside of the                  several wells have peaked interest in the play. CHK’s farm-out
Wattenberg field, historically the source of production out of the                to CNOOC ($4,500/acre) and MRO’s farm-out to Marubeni
DJ Basin targeting tight sands intervals below the Niobrara.                      ($5,000) established valuations north of the Wattenberg. EOG
While vertical activity in the Wattenberg will increase (Weld                     brought in an early successful well at ~1.5 kbd and SM tested a
County, Colorado ~50kbd), the focus is on horizontal drilling                     well in the Silo field at +1 kbd. However, companies’ 1Q11
targeting the Niobrara not only in the outer reaches of the DJ,                   earnings updates generally shed limited insight on recent
but also in other basins in the Rockies such as the North Park                    activity, and 2Q11 results should help define the play further.
and Powder River basins.                                                          While investors are looking for an analogue to the Bakken, the
                                                                                  heterogeneity of the play will take time to more fully de-risk the
We forecast Niobrara production to increase ~80kbd                                fairway.
through 2012. Within our production model, Niobrara
                                                                                  Exhibit 35
forecasts have the most variability as historical well
performance is generally not known. Over the previous
                                                                                  Niobrara Well Economics Compared
                                                                                  80
24-months a land grab has occurred with many producers                                                    Required Strip for 10% IRR




                                                                                                                                                                                                                                                                                                              67
                                                                                  70
leasing up large portions of the play. The data point being




                                                                                                                                                                                                                                                                                 62


                                                                                                                                                                                                                                                                                               62
                                                                                                                                                                                                                                                                  58
observed in the play is whether the Niobrara formation is




                                                                                                                                                                                                                                                     57
                                                                                  60




                                                                                                                                                                                                                55


                                                                                                                                                                                                                                 55
                                                                                                                                                                                          54
                                                                                                                                                          51


                                                                                                                                                                          51
prospective utilizing a horizontal drilling program. Vertical                     50




                                                                                                                                            45
                                                                                                                             44
                                                                                                                42
                                                                                        40




production in the Wattenberg is well established, however, we                     40

believe significant incremental growth could come from                            30

unconventional Niobrara production.                                               20


                                                                                  10
Exhibit 33
Acreage Holders                                                                    0
                                                                                                                                                                      Permian - Spbrry
                                                                                                              Permian -



                                                                                                                          (Horizontal)
                                                                                        Bakken (Sanish)




                                                                                                                                                                                                             Bakken (West
                                                                                                                                         Permian - Bone




                                                                                                                                                                                                                                                   Wolfcamp


                                                                                                                                                                                                                                                               (Condensate)

                                                                                                                                                                                                                                                                              Bakken (East




                                                                                                                                                                                                                                                                                                              Eagle Ford (Oil)
                                                                                                                          Carbonates




                                                                                                                                                          Niobrara




                                                                                                                                                                                          Permian - Avalon




                                                                                                                                                                                                                                 Mississippian




                                                                                                                                                                                                                                                                                               Three Forks
                                                                                                              Wolfberry




                                                                                                                                                                                                                                                   Permian -


                                                                                                                                                                                                                                                                Eagle Ford
                                                                                                                                                                                                               Williston)




                                                                                                                                                                                                                                                                                Nesson)
                                                                                                                                                                        (110 mboe)



             Large Caps                                   Small-Mid Caps
                                                                                                                                             Spring




APC                         1,260,000           KWK                    197,000
NBL                           830,000           QEP                    154,600
CHK                           570,000           BBG                    103,000    Source: Company data, Morgan Stanley Research estimates
DVN                           220,000           PETD                     74,100
EOG                           220,000           WLL                      73,115
MRO                           133,000           DBLE                     71,248   We forecast Niobrara to grow ~80kbd growth over next
                                                CRZO                     62,000   18-months. We forecast incremental horizontal production by
                                                GMXR                     40,260   forecasting expected growth in the horizontal rig count. We
                                                REXX                     39,000   assume incremental vertical activity maintains current
Source: Company data, Morgan Stanley Research                                     Wattenberg production levels. In our opinion, transportation
                                                                                  bottlenecks will come in the form of rapid growth of the
Exhibit 34
                                                                                  Niobrara formation and much larger definition of the economic
Niobrara Recoverable Resource Estimate
                                                                                  boundaries of the DJ Basin. With ~32 horizontal rigs currently
                                                                       Niobrara   running, we see that growing to 55 rigs by the end of next year.
Aereal Extent (Sq. Miles)                                                8,400
Acerage                                                              5,376,000    Exhibit 36
Fluid Type                                                                  Oil   Niobrara Production Build
OOIP / Section                                                          75,000                                                                                       2Q11                3Q11                        4Q11                         1Q12            2Q12                   3Q12                4Q12
Recovery Factor                                                          0.3%     Rig Count                                                                           32                            35                      39                      43                   47                   51                     55
Spacing (on 1280)                                                           16     Growth %                                                                                              9.4%                 11.4%                              10.3%          9.3%                   8.5%                  7.8%
Total Recovered / Section (mboe)                                         3,000    Existing Production (Declined)                                                      53                            52                      51                      50                   49                  48                     47
Total Recoverable (Mmboe)                                               25,200    Cum'l. Production Added (kbd)                                                       15                            38                      48                      56                   65                   74                     82
                                                                                  End Total Production (kbd)                                                          68                            90                      99                     106               114                     122              129
Peak Production (mboepd)                                                 1,000
                                                                                  Source: Company data, Morgan Stanley Research estimates
R/P                                                                         69
Source: Company data, Morgan Stanley Research estimates




                                                                                                                                                                                                                                                                                                              20
                                                                                        MORGAN             STANLEY                   RESEARCH

                                                                                        June 30, 2011
                                                                                        Refining & Marketing




Exhibit 37                                                                              operation capable of 30kbd (including 20kbbl of local storage).
2011 Horizontal Rigs Planned                                                            White Cliffs expansion to 50kbd will alleviate near-term
                                       2011 Hz. Rigs
                                                                                        constraints, but longer term transportation is likely to be
APC                                       2-4    PETD                              1
                                                                                        needed. Operators in the Northern portions of the DJ Basin
CHK                                    5-10      REXX                              1
                                                                                        could connect to KinderMorgan’s Platte system (165kbd) which
CLR                                       1-2    SM                                1
NBL                                        4     GMXR                              1
                                                                                        would deliver to Wood River, IL, but no plans have been
BBG                                       1-2    CRZO                              1    publicly disclosed.
Source: Company data, Morgan Stanley Research
                                                                                        Exhibit 39
                                                                                        Niobrara Production vs. Takeaway Capacity
Exhibit 38                                                                                300
                                                                                                                                                   Connection to Platte
Niobrara Pipelines                                                                                        Daily Production (kbd)                   would add 165kbd
Current                                                                                   250             Throughput (kbd)
                                                              Nameplate
Operator          Origin     Destination        Name           Capacity   Utilization
SemGroup          DJ Basin   Cushing            Whitecliffs         50          61%       200
                                                                                                        White Cliffs is only
Future Possible                                                                                         interstate pipeline out of
                                                              Nameplate     Expected      150           the DJ
Operator          Origin     Destination        Name           Capacity   Completion
KinderMorgan      Casper     Wood River         Platte             165     24 mos. +
                                                                                          100
Source: Company data, Morgan Stanley Research

                                                                                           50


Modest Niobrara production growth will most likely                                           0
                                                                                                 Jun-     Sep-    Dec-    Mar-       Jun-   Sep-    Dec-    Mar-   Jun-   Sep-   Dec-
pressure existing infrastructure. The only crude interstate                                       11       11      11      12         12     12      12      13     13     13     13
transportation out of the DJ Basin (Platteville, CO) to Cushing
                                                                                        Source: Company data, Morgan Stanley Research estimates
is SemGroup’s White Cliffs pipeline, completed in 2009, which
has capacity of ~30kbd with expansion potential to 50kbd.
Current DJ Basin crude production is ~50kbd. White Cliffs
utilization is near current capacity and trucks are used to
handle excess barrels. SemGroup also operates a trucking




                                                                                                                                                                                  21
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                                                                                     June 30, 2011
                                                                                     Refining & Marketing




Other Emerging Plays
                                                                                      Exhibit 41
Our production model does not include “Other” Crude/NGLs
production growth effecting Cushing coming which we see                               Woodford Build
                                                                                                                       2Q11   3Q11   4Q11   1Q12     2Q12     3Q12   4Q12
coming from three primary plays over the near-term: (1)
                                                                                      Rig Count                         32      32     32       35     35       35     35
Woodford (Anadarko), (2) Mississippian Lime, and (3) Alberta                           Growth %                               0.0%   0.0%   9.4%     0.0%     0.0%   0.0%
Bakken. We see the potential for an incremental ~140kbd                               Existing Production (Declined)     3       3      3        3      2        2      2

coming online over the next 18 months, which on top of growth                         Cum'l. Production Added (kbd)     10      33     45       56     64       71     76
                                                                                      End Total Production (kbd)        13      36     48       59     66       73     78
forecasts from Canada, the Bakken, and the Permian will
                                                                                      Source: Company data, Morgan Stanley Research estimates
cause further pressure on Cushing takeaway. We expect
other “new plays” to emerge and add additional growth
                                                                                      The Woodford is poised to grow into a significant
volumes as technology, geology, and capital define the North
                                                                                      onshore unconventional resource. The Woodford shale in
American tight oil potential.
                                                                                      the Anadarko basin has a higher liquids cut (40/60) across
                                                                                      Canadian County, Oklahoma, with DVN, XEC, and CLR
We have modeled out the Woodford (Anadarko Basin),
                                                                                      focused on bringing production online. XEC is ramping to 10
Mississippian Lime, and Alberta Bakken, yet only include
                                                                                      rigs in the play and drilling one well per section with optimal
the Woodford in our overall production forecast. There
                                                                                      downspacing to be announced later this year. DVN tested
are ~32 rigs running in the Woodford (Anadarko Basin), 20
                                                                                      500’ spacing (5 wells per section) with “positive” results.
rigs in the Mississippian Lime, and under 10 rigs estimated in
                                                                                      Investors will monitor the downspacing results closely as the
the Alberta Bakken. DVN, CLR, XEC, HK, CHK, and NFX are
                                                                                      prospectivity of the play will be greatly enhanced.
active in the Woodford. SD, CHK and several private
operators are active in the Mississippian Lime, and Shell,                            Exhibit 42
MUR, and DTX-TSE are active in the Alberta Bakken. Our                                Woodford Recoverable Resource
combined production forecast of these plays is 100kbd                                                                                                          Woodford
through next 12 months. Our rig count forecast is moderate                            Aereal Extent (Sq. Miles)                                              1,200-1,500
increasing from 51 to 63 over the same period.                                        Acerage                                                                 800k-1mm
                                                                                      Fluid Type                                                            60/40 Gas:Oil
                                                                                      Locations                                                                  10k-12k
Exhibit 40
                                                                                      Type Well EUR (mboe)                                                           450
Total “Other” Production Build                                                        Potential Resource (mmboe)                                             4,000-5,000
                                 2Q11   3Q11   4Q11   1Q12      2Q12   3Q12   4Q12    Production Esitmate (mboepd)                                                   500
Rig Count                         51     52      54        62    62     62     63     R/P                                                                          22-27
 Growth %                         0%     NA    200%   92%        0%    31%    14%
                                                                                      Source: Company data, Morgan Stanley Research estimates
Existing Production (Declined)     9      8       8         8     7      7      7
Cum'l. Production Added (kbd)     17     58      82       101   117    130    139
End Total Production (kbd)        26     67      90       109   124    137    146
                                                                                      The Mississippian Lime program is employing
Source: Company data, Morgan Stanley Research estimates
                                                                                      unconventional drilling in a conventional play. The
                                                                                      “Mississippian” is a carbonate stratigraphic trap with wells
Our production added estimate, similarly uses type wells per
                                                                                      drilled between 4,500 to 7,500 feet. The formation is known to
play to estimate a pro forma production stream. Our Woodford
                                                                                      have relatively high porosity and permeability with pay more
type well is a 450mboe EUR well assuming a 40% liquids cut.
                                                                                      than 100 feet thick in places. Vertical wells have traditionally
We assume 30-day completions with our monthly well count
                                                                                      made up exploration in the Mississippian (~1,200), but several
increasing to 35 through 2012. In the Mississippian Lime we
                                                                                      operators believe a horizontal program can be brought to the
use SD and CHK estimates for our type well, a 400mboe EUR
                                                                                      play. Both SD and CHK have ~1mm acre positions, private
and 300bpd IP, which is slightly more conservative than
                                                                                      companies in the play include Ceja Corp., Eagle Energy (40k
currently available company estimates. With 19 rigs running
                                                                                      acres), Chaparral (66k acres), Ram Energy Resources (53k
and 20 day completions, completed wells brought online rises
                                                                                      acres), and Red Fork Energy (12k acres). SD has devoted
29 through next year. Our Alberta Bakken estimate assumes
                                                                                      over $1bn to a development program and could double its rig
little production growth as it is early in the play with well results
                                                                                      count from 12 to 24 in the next 12 months.
mixed. Our production build assumes a ramp to 8 rigs bringing
on less than 10kbd in production through 2012.




                                                                                                                                                                      22
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                                                                                       June 30, 2011
                                                                                       Refining & Marketing




Exhibit 43                                                                              Exhibit 45
Mississippian Lime Build                                                                Horizontal Impact to FST’s Texas Panhandle
                                 2Q11   3Q11   4Q11    1Q12    2Q12    3Q12     4Q12    Position
Rig Count                         19      19     19       22     22      20       20
                                                                                          40,000                        # Wells   EUR/Sec. D&C/Sec. F&D
 Growth %                               0.0%   0.0%   15.8%    0.0%   (9.1%)   0.0%
                                                                                                     20-acre vertical     32       47       $74    $1.59
Existing Production (Declined)     6       6      5       5       5       5        4      35,000     Twin Hz.             _6        42      $50    $1.20
                                                                                                     20-Acre v. Twin Hz. (26)     (5)     ($24)  ($5.20)
Cum'l. Production Added (kbd)      7      24     35       43     49      54       57
End Total Production (kbd)        13      30     40       48     54      59       61      30,000

Source: Company data, Morgan Stanley Research estimates                                   25,000

                                                                                          20,000
Exhibit 44
                                                                                          15,000
Alberta Bakken Build
                                 2Q11   3Q11   4Q11    1Q12    2Q12    3Q12     4Q12      10,000
Rig Count                          0       1      3        5      5       7        8
                                                                                           5,000
 Growth %                                NA    200%   66.7%    0.0%   40.0%    14.3%
Existing Production (Declined)     0       0      0       0       0       0        0          0
Cum'l. Production Added (kbd)      0       0      1        2      3       5        6          Apr-09            Jun-09             Aug-09          Oct-09      Dec-09          Feb-10
End Total Production (kbd)         0       0      1        2      3       5        6

Source: Company data, Morgan Stanley Research estimates                                 Source: Company data, Morgan Stanley Research



It is still too early in the Alberta Bakken to make                                     There will continue to be announcements regarding new
significant incremental production growth forecasts. It is                              plays and extensions of established basins for the
early in the play’s history with much activity and leasing                              foreseeable future. Extending conventional established
occurring last year. The play extends from Alberta down to                              plays (Permian, DJ, Western Sedimentary Basin) via
Montana and producers are exploring both the Canadian and                               unconventional completion technology and targeting other
US side of the play actively. The play looks to be bounded on                           unconventional intervals (Three Forks, Wolfcamp, Niobrara)
the east side of the fairway, with source rock black shale                              are a major part of the North American production growth
(Exshaw) located to the west of the emerging fairway. Results                           forecast. Also, the Western Canadian Sedimentary Basin
have been variable to date with Shell, Crescent Point, MUR,                             contains the 3rd largest reserves of oil, is over 540,000 square
Rosetta, and Deethree exploring in the play. Limited well                               miles and underlies many of the Canadian provinces
results have been released to date but industry is discussing                           including; Alberta, Saskatchewan, British Columbia, and
800-1000 bpd initial production rates for a successful well and                         Manitoba. While conventional fields are relatively mature, by
OOIP of 13-15 mmboe per section.                                                        drilling horizontal wells with multi-stage fracs in conventional
                                                                                        reservoirs has led to the reversal of declines and the most
A strong commodity pricing environment and technology                                   recent land grab and series of highly watched emerging tight
will further oil-rich onshore exploration. Producers have                               oil plays indicates potential upside to our estimates. There are
responded to oil’s strength as they have sought to develop                              other plays outside of the established areas which have
new plays and extend technology in established basins. The                              become a focus too, the Utica, Monterey, and Tuscaloosa that
major plays (Bakken, Permian, and Eagle Ford) are economic                              are poised to become major oil rich resource plays.
above $65/bbl, but commodity pricing is only part of the                                Exhibit 46
dialogue. Technology developed over the last decade in                                  New Plays & Focus of Investor Interest
unconventional gas plays is now being applied on oil rich
                                                                                         New U.S. Unconventional Oil Plays
unconventional plays. FST’s results in the Permian are
illustrative of the benefits of a horizontal program. See exhibit
46.                                                                                                                                                What's next?
                                                                                                                                                                           Tuscaloosa
                                                                                                                                                                             Marine
                                                                                                                                                                   Monterey
                                                                                                                                                               Collingwood
                                                                                                                                                                  Utica
                                                                                                                                                     Mississippian
                                                                                                                                                         Lime
                                                                                                                                            Woodford-Cana
                                                                                                                                     Permian Hz.
                                                                                                   Eagle Ford
                                                                                                                                                                   Investor focus on new
                                                                                                     Niobrara                                                       plays is accelerating
                                                                                        Bakken ('06/'07)

                                                                                           1Q09       2Q09       3Q09        4Q09      1Q10        2Q10     3Q10    4Q10      1Q11      2Q11

                                                                                        Source: Company data, Morgan Stanley Research




                                                                                                                                                                                            23
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                                                                                          June 30, 2011
                                                                                          Refining & Marketing




Majors and E&P FCF: Cashed Up to Drive Growth
Majors have ability to spend. We believe Integrated Oils and                              oil-rich conventional and unconventional plays. With high
E&P’s will support higher production growth as cash flows                                 reserve life and stable fiscal regimes, we believe the Majors are
surpass 2008 levels on higher oil prices. We estimate the                                 attracted to the onshore North American plays. As Gulf of
Integrated Oils and E&P’s will generate over $75 Bn of free                               Mexico (GoM) activity remains slow, conflict in MENA region,
cash flow this year, rising to over $90 Bn in 2013 on a flat $100/                        and gas price remain low relative to crude, the Majors will likely
bbl (Brent) crude deck. On a reduced $80/bbl deck, the group                              continue to allocate incremental capital spending towards oil
will still generate $40 Bn on average through 2013, which                                 rich plays, a continuing trend in the last 12 months. We believe
includes increased capital spending compared to 2010.                                     recent acquisitions by the Majors and focus on unconventional
                                                                                          resource during most recent analyst days validate the trend.
Exhibit 47
Integrated and E&P’s Generate Cash >$80/bbl Brent                                         E&Ps shifting toward liquids. We also include large cap
                                            2011      2012         2013        2014
Integrateds
                                                                                          Exploration and Production companies with growing exposure
  FCF @ $120/bbl                             76.1      90.5         85.9       88.6       to oil rich plays, as all are trying to become more “oily”. As
  FCF @ $100/bbl (base case)                 75.7      83.0         82.6       85.7       highlighted throughout, we see the E&P sector as building
  FCF @ $80/bbl                              46.6      38.6         42.9       45.1
Average YoY Production Growth              -0.7%      5.4%         7.4%       5.0%        meaningful positions within the established plays as well as
                                                                                          more being more likely to move into and develop new liquids
E&P (Lower 48 oil-focused)
 FCF @ $120/bbl                               2.7      10.7         17.1       23.3       plays, which would be incrementally bullish to our analysis.
 FCF @ $100/bbl (base case)                   1.4       4.9          9.5       14.6       E&P funding levers are readily available in the capital markets,
 FCF @ $80/bbl                               -3.2      -2.4          2.6        7.1
Average YoY Production Growth              20.2%     16.1%        12.3%      10.4%        M&A, and A&D markets, which serve to fund onshore growth.
Integrated Oils include: CVX, COP, XOM, HES, MRO, MUR, OXY;
E&Ps include: APA, APC, EOG, NBL, OAS, PXD, PXP, XEC                                      We see higher capital raising by companies, moves by Majors
Source: Company data, Morgan Stanley Research
                                                                                          to acquire further acreage, and money from int’l players to fund
Integrated Oils adding acreage and have access to                                         growth as signs of higher incremental spending drive
resource. We have gone through Integrated Oil portfolios                                  production growth over not only the next 12-months, but longer
which we see holding of over 11MM net acres across the major                              term as well.



Exhibit 48
Majors Have Access to Resource: Net Acreage Holdings Across Shale Plays That Feed Into Cushing
                                                                                                  Woodford       Alberta                             Total
                                          Permian      Eagle Ford           Bakken Niobrara      (Anadarko)      Bakken    Cardium    Duvernay    Company
ConocoPhilips (COP)                      1,040,000            220,000       460,000                                        137,000                1,857,000
Chevron (CVX)                            1,130,000                                                                                     200,000    1,330,000
ExxonMobil (XOM)                         2,156,000            120,000       410,000                 205,000                235,000                3,126,000
Hess (HES)                                                     90,000       900,000                                                                 990,000
Marathon Oil (MRO)*                                           216,000       391,000    133,000       94,000                                         834,000
Murphy Oil (MUR)                                              250,000                                            150,000                            400,000
Occidental (OXY)                         2,400,000                          200,000                                                               2,600,000
Total Acreage                            6,726,000            896,000      2,361,000   133,000      299,000      150,000   372,000     200,000 11,137,000
*MRO pro-forma for pending HilCorp aqcuisition
Source: Company data, Morgan Stanley Research




                                                                                                                                                        24
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                                                                                                               June 30, 2011
                                                                                                               Refining & Marketing




Historical Precedent: US Natural Gas Market of 2006-08
Unconventional natural gas development has important                                                           Gas producers faced incentives promoting increased
precedential implications for onshore unconventional oil                                                       production in the face of a declining forward curve. In
plays. Many observers point to the acceleration of activity in                                                 essence, producers were making capex decisions based on
the Ft. Worth Basin’s Barnett Shale as illustrative of a “shale”                                               factors other than economics, hedging (contango in the
revolution in the last decade. While the history of George                                                     forward curve), HBP lease terms, and JVs drove drilling
Mitchell making shale gas production economic in the Barnett                                                   decisions. In concert with those factors was a well defined gas
is well known, what is more impactful is that the pioneering                                                   storage infrastructure which developed “seasonality” as
completion techniques he and others employed in the Barnett                                                    injections in anticipation for summer cooling season were
were utilized, with similar results, in other gas plays like the                                               followed by withdrawals, followed by a fall injection season in
Marcellus, Haynesville, and Fayetteville.                                                                      anticipation of the traditional winter withdrawals.

Exhibit 49                                                                                                     Exhibit 51
Historical Barnett Production & Well Count                                                                     Storage Seasonality Provides Support for Increased
  2,000                                                                                               16,000
                                                                                                               Production Too
                   Bcf
  1,800            Well Count                                                                                             8.0
                                                                                                      14,000
                                                                                                                                                                                                                                                                                                                                                                                $14.00
  1,600                                                                                                                   6.0                                                                             Implies withdrawal above / injection below baseline expectations
                                                                                                      12,000                                                                                                                                                                                                                                                                    $12.00
  1,400                                                                                                                   4.0

                                                                                                      10,000                                                                                                                                                                                                                                                                    $10.00
  1,200
                                                                                                                          2.0




                                                                                                                                                                                                                                                                                                                                                                                         $/MMBtu
                                                                                                                Bcf/day




  1,000                                                                                               8,000                                                                                                                                                                                                                                                                     $8.00
                                                                                                                          0.0

   800                                                                                                                                                                                                                                                                                                                                                                          $6.00
                                                                                                      6,000               (2.0)

   600                                                                                                                                                         Supply/Demand Balance (Bcf/d)
                                                                                                                          (4.0)                                                                                                                                                                                                                                                 $4.00
                                                                                                      4,000                                                    Natural Gas Front-Month ($/Mcf)
   400
                                                                                                                          (6.0)                                                                                                                                                                                                                                                 $2.00
                                                                                                      2,000                                                                                                               Implies withdrawal below / injection above baseline expectations
   200
                                                                                                                          (8.0)                                                                                                                                                                                                                                                 $0.00
                                                                                                                                  1/1/99

                                                                                                                                           7/16/99

                                                                                                                                                     1/28/00

                                                                                                                                                               8/11/00

                                                                                                                                                                         2/23/01

                                                                                                                                                                                   9/7/01

                                                                                                                                                                                            3/22/02

                                                                                                                                                                                                      10/4/02

                                                                                                                                                                                                                4/18/03

                                                                                                                                                                                                                          10/31/03

                                                                                                                                                                                                                                     5/14/04

                                                                                                                                                                                                                                               11/26/04

                                                                                                                                                                                                                                                          6/10/05

                                                                                                                                                                                                                                                                    12/23/05

                                                                                                                                                                                                                                                                               7/7/06

                                                                                                                                                                                                                                                                                        1/19/07

                                                                                                                                                                                                                                                                                                  8/3/07

                                                                                                                                                                                                                                                                                                           2/15/08

                                                                                                                                                                                                                                                                                                                     8/29/08

                                                                                                                                                                                                                                                                                                                               3/13/09

                                                                                                                                                                                                                                                                                                                                         9/25/09

                                                                                                                                                                                                                                                                                                                                                   4/9/10

                                                                                                                                                                                                                                                                                                                                                            10/22/10

                                                                                                                                                                                                                                                                                                                                                                       5/6/11
     0                                                                                                0
          1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010


Source: Texas RRC, Morgan Stanley Research                                                                     Source: EIA, Morgan Stanley Research


Examining the increase in wells drilled and the increase in                                                    Analogous to unconventional gas, unconventional oil
production shows how quickly the industry changed. Producers                                                   producers will face similar incentives. Similar to gas
were incented to grow production as quickly as possible, and                                                   producers, unconventional oil players face incentives to drill in
could do so by employing horizontal drilling programs.                                                         the form of a moderately strong contango, incenting hedging,
                                                                                                               delaying drilling/completions, incenting JV/monetizations, and
Exhibit 50                                                                                                     lease terms which compel the continuation of drilling to retain
The Barnett as model, Shale gas production                                                                     mineral ownership. As with gas, oil production will continue to
accelerated very quickly                                                                                       increase until the forward curve incents the discontinuing of
  3,000                                                                                                        capital outlays. Gas producers were hesitant to do this as core
                   Eagle Ford                                                                                  economics of the best plays, (Marcellus) were positive well
  2,500            Woodford
                                                                                                               below benchmark pricing. Because of the above factors the
                   Marcellus
  2,000                                                                                                        gas market saw supply growth continue into a declining forward
                   Haynesville                                     BCF Annually
                   Fayetteville
                                                                                                               curve; domestic crude supply is likely to see similar effects.
  1,500
                                                                                                               Just as gas producers were incented to grow production in
  1,000                                                                                                        order to hold acreage (whose cost increased dramatically in the
                                                                                                               various sequential land grabs) and to delay completion as
    500
                                                                                                               higher pricing appeared achievable in the long dated contracts,
      0                                                                                                        oil producers face similar incentives which will increase supply.
            2000    2001       2002   2003   2004   2005    2006     2007   2008    2009    2010
                                                                                                               Only when the back of the curve is continually sold will
Source: EIA, Morgan Stanley Research                                                                           producers be incented to decrease production.




                                                                                                                                                                                                                                                                                                                                                                                25
                                            MORGAN        STANLEY   RESEARCH

                                            June 30, 2011
                                            Refining & Marketing




Exhibit 52
Map of Crude Oil Pipelines and Refineries




Source: CAPP, Morgan Stanley Research




                                                                               26
                                                                                  MORGAN        STANLEY       RESEARCH

                                                                                  June 30, 2011
                                                                                  Refining & Marketing




Pipelines – Cushing Outbound
Three new projects to get crude out of Cushing and to the                         Major Pipeline Takeaway Capacity Background
Gulf Coast. There are now three potential new pipeline
projects out of Cushing: (1) EPD/ETP JV, (2) Keystone XL and                      Keystone XL (500 mbpd, TransCanada, expected 1H 2013).
(3) Enbridge Monarch and one potential pipeline reversal,                         The 500 mbpd expansion to the Keystone system (591 mbpd
Seaway. EPD ETP JV and Keystone XL are the likely winners                         currently) will be built in two parts: from Hardisty, Canada to
and we expect three lines will get built in 2013, albeit likely with              Steele City, KS, and Cushing, OK to Houston and Port Arthur.
delays and we model reduced volumes compared to current                           Since the pipeline crosses the US-Canada border, a
nameplate capacity. The two existing Cushing to Gulf Coast                        Presidential Permit is required and the pipeline is subject to the
projects are Keystone XL and Monarch, both of which have                          National Environmental Protection Act (NEPA). The pipeline
issues that hinder their ability to move forward in construction.                 faces environmental opposition, viewing the pipeline as
Keystone XL operator, TransCanada, has secured valuable                           bringing in more environmentally impactful oil sands to the US.
crude shipper commitments but has seen delays by                                  In 2010, Congressional representative and environmental
environmental regulation which has pushed start-up into 2Q                        groups spoke out against the pipeline with the EPA declaring
2013 from prior guidance of 2012.                                                 the Draft Environmental Impact Statement (DEIS) inadequate.
                                                                                  The State Department followed up with a Supplemental DEIS.
Enbridge has secured permits to build Monarch yet lacks                           The EPA sent a letter to the State Department on June 6, 2011
shipper commitments. The EPD/ETP JV has a clear advantage                         asking for additional analysis on oil spill and environmental
over Enbridge Monarch because it utilizes existing pipelines                      effects. The State Department is now reviewing over 100,000
that saves on costs and time. EPD/ETP JV converts an existing                     responses following the public comment period, with a
240 miles of natural gas pipes and only proposes constructing                     Congressional panel setting a November 1 deadline for a
354 miles of new pipe. We assume that EPD and ETP have a                          decision. Public sentiment has turned in favor of the pipeline
competitive advantage over Monarch because we expect they                         following higher oil prices. TransCanada expects to complete
will likely pass some of their construction cost savings onto                     the project in late 2012, and we expect completion in 2H 2013.
customers in the form of lower tariffs vs. Monarch. Further, we
                                                                                  Double E (450 mbpd, Enterprise Product Partners and
believe the first project to secure shipper commitments will
                                                                                  Energy Transfer Partners JV, expected in 4Q 2012). The
cannibalize other projects: unlikely in our view to obtain enough
                                                                                  pipeline, announced in late April, plans to utilize existing
to bring all three pipelines on in 2013.
                                                                                  pipelines to speed approval and development process. The
Exhibit 53                                                                        pipeline will run from Enterprise’s 3.1 MMbbl storage facility in
Future Cushing Evacuation Capacity and Reversals                                  Cushing, OK to Enterprise’s ECHO crude oil and storage
                  Capacity(kbpd)      Start-up   Owners/Operators                 facility in Houston. Energy Transfer plans to contribute its
Outbound                                                                          natural gas pipeline in East Texas, with only 60% of the project
Keystone XL               500         2Q 2013    TransCanada
Monarch                   350         1Q 2013    Enbridge                         requiring newbuild construction. The JV announced start of
EPD/ETP JV                400         YE 2012    Enterprise and Energy Transfer   open season on May 25, continuing until July 8, service
Reversal                                                                          expected to begin in 4Q 2012. We expect a one quarter delay
Seaway                    350         YE 2012    Enterprise and ConocoPhillips    in completion due to permitting and bottlenecks from significant
Longhorn                  75          YE 2012    Magellan
                                                                                  pipeline construction in the US.
Source: Company data, Morgan Stanley Research estimates
                                                                                  Monarch (350 mbpd, Enbridge, completion uncertain).
Seaway: The fourth option out of Cushing returns. The                             The pipeline is an expansion of the current Enbridge system
potential for a Seaway reversal has reemerged with EPD’s                          from Cushing to Houston with initial capacity of 150 mbpd,
announcement to form a new JV with ETP. With Seaway’s                             expandable to 350 mbpd. The company began discussing the
current volume at less than 11% of capacity (350kbpd) and                         project in Fall 2010, with a tentative start date of late 2012,
imminent new-build construction set to be operational by                          early 2013. However, receiving shipper commitments became
year-end 2012, we believe that COP could consider either                          an issue, and the company has converted the pipeline to a
selling its 50% interest to EPD or holding an open season and                     fixed toll. The start date has been pushed to sometime in 2013,
reversing the asset to make returns. In our opinion, if Seaway                    and we believe the project may not be completed as the Double
reverses, then EPD will most likely not build the JV pipeline                     E and Keystone XL pipeline crowd out initial need for Monarch.
with ETP. We do not believe Seaway will be reversed.




                                                                                                                                                27
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                                                                                 June 30, 2011
                                                                                 Refining & Marketing




Rails
Rail is a solution to move crude out of the Bakken, past                         Unit train economics and cost description. According to
Cushing and Patoka. Currently used by Bakken producers,                          BNSF, a typical 70kbbls unit train requires: 3 locomotives, 2
rail remains a possible solution for bypassing the Cushing                       buffer cars and 118 tank cars. To maintain logistical
bottleneck. The commonly used name for the crude rail system                     economics most unit trains are at least carrying 50kbbls of
is called “Unit Train.” Unit trains are currently being used by                  crude oil as the operating leverage of the locomotives. Timing
EOG who moves ~40-50kbpd of crude. Hess will potentially                         of transport paired with the transloading terminal capacity
move 120kbpd at its Tioga terminal after it is completed in 2012.                constraints allow for optimal rail economics. The average
Canadian producers have also intermittently used rail to ship                    crude oil tank car holds 650-700 bbls of crude and costs
barrels to North America.                                                        ~$6.50/bbl from North Dakota to Stroud, OK and ~$7.25/bbl
                                                                                 from North Dakota to St James, LA. Using unit trains requires
Exhibit 54                                                                       an additional cost, producers would likely have to construct a
Main routes out of the Bakken to Houston                                         transloading facility and truck the final distance to the refineries
                                                                                 at a cost of $10-$15mm. The cost of a facility adds an
                                                                                 additional $0.25-$0.50/bbl, assuming one unit train per day for
                                                                                 18 months (after which operators will use major pipelines). Rail
                                                                                 is an economic solution to moving Bakken crude to the Gulf
                                                                                 Coast as the LLS to WTI spreads remain over $8/bbl netting
                                                                                 producer the arbitrage the spread less rail costs per bbl and
                                                                                 other up front capex for transloading terminals.

                                                                                 Exhibit 56
                                                                                 Bakken Rail map




Source: BNSF, Morgan Stanley Research


The typical process for rail is to move crude from the well head
via short line pipelines or trucks to a transloading terminal
facility. These transloading facilities load up to 30-60kbbls of
crude into rail cars in less 24 hours and then move south to
Stroud Oklahoma or further to St James, LA to another
transloading terminal that offloads crude directly into another                  Source: Company data, Morgan Stanley Research
pipeline or refinery within 48 hours. These trains then recycle
back to their origin and moves continue the process.                             Unit trains are contracted from 1 to 5 years with the major rail
                                                                                 carriers BNSF, CSX etc. Most operators lease locomotives
Exhibit 55
                                                                                 and crude tank cars to operators while 3rd party or producers
Rail logistics out of the Bakken
                                                                                 build transloading terminals. The major limiting factor for unit
Rail Transportation                        2010       2011      2012      2013
Various Sites including                  30,000     30,000    30,000    30,000   trains is not crude oil tank cars but the transloading terminals
EOG Rail                                 65,000     65,000    65,000    65,000   particularly the receiving end in St James, LA.
Dakota Transport Solutions               20,000     40,000    40,000    40,000
Hess Rail                                                     60,000    60,000
Rangeland COLT Hub                                            27,000    27,000
Rail Only                               115,000    135,000   222,000   222,000
Source: Company data, Morgan Stanley Research estimates




                                                                                                                                                 28
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                                                                                    June 30, 2011
                                                                                    Refining & Marketing




Exhibit 57
Train Transportation All-In Costs
                                                             Time
Distance                                             Miles   (hrs)     $Cost /bbl
North Dakota to Stroud, OK                            950      16         $6.58
Stroud, OK to St. James, LA                           650      11         $7.23

Potential Economics
Differential                                                               $8.00
Profit/bbl (Differential less Avg. cost/bbl)                               $1.09
Bbls/Train                                                                49,980
Arbitrage (total value)                                                  $54,643
Cost of Facility                                                     $10,000,000
Trips for Payback                                                            183
Source: Company data, Morgan Stanley Research estimates


Currently the Bakken region has 3 major transloading terminals
primarily from EOG and Dakota Transloading Solutions with
135kbpd of capacity. By 2012 Hess Tioga, EDOG and
Rangeland COLT will add an incremental ~90kbpd. On the
other receiving end major hubs include Stroud, OK 50kbpd and
St James, LA 20kbpd. Kansas City Southern is planning to
build and operate a rail terminal in Port Arthur by 2Q12 to
receive Bakken crude. Costs to construct transloading
terminals can run from $20-40mm for 50kbbls offtake and take
nearly 6 months to 1 year to construct.




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                                                                    June 30, 2011
                                                                    Refining & Marketing




Barge
Barges provide an alternative means to reduce the                   Cushing crude to the Gulfcoast next to pipelines. We assume
bottleneck at Cushing. Barges were once a preferred                 that most barges could unload crude oil into the LOOP or
method of crude transport until pipelines became the preferred      LOCAP system that flows into all the major Gulfcoast crude
method of transportation. Currently barges are still a preferred    pipeline systems while most Gulfcoast refineries have their
method for coastal assets to move crude, refined product,           own dock systems to offload crude.
chemical feedstocks and asphalt up and down the Mississippi
River and throughout the Intracoastal Waterway. We know of          The current market for the barges is in relative balance
two major players in the barge market, Kirby and Marathon that      which is much like that of trucking, heavy demands for
make up nearly one third of the barge capacity of the inland US     chemical and feedstocks cannibalize the existing inventory of
barge market (3,100 barges). Of that Kirby uses 14% or 112          barges and the amount of excess capacity has already taken
barges in its fleet to move crude oil and we assume since Kirby     place in 2008 when many barges were sold for scrap and taken
is the largest barge operator in the United States that the total   off the market due to overbuilding. To meet crude shipping
barges are 14%. Of Marathon’s 183 barge fleet ~25 barges are        demands new barges could be built, but would cost nearly
used to move crude oil and the remainder move the other             $3mm (30 tons or 21kbbls). Manufacturing lead time is not an
liquids and feedstocks.                                             issue, newbuild constraints lie in shipyard capacity and the
                                                                    economics to justify the project. Barge operators would require
Exhibit 58                                                          a long term agreement of nearly 5-10 years based on current
Inland waterway map                                                 economics or less if rates were increased or price arbitrage of
                                                                    the WTI LLS spread and shipping cost. Towboats are another
                                                                    potential headwind for barges as that market is tight as well,
                                                                    bringing additional towboats into service takes ~15 months.

                                                                    Exhibit 59
                                                                    Total barges in the United States




                                                                    Source: Kirby Corp, Morgan Stanley Research
Source: Kirby Corp, Morgan Stanley Research
                                                                    Barges, rails and truck comparison. Based on our analysis
Barge economics are closest to those of pipelines.                  we believe moving ~15kbpd of crude, a barge would need to
According to KEX, a typical 90kbbls barge requires: 1 towboat       carry 100kbbls of crude that would take ~7 days to move 4
and 4 barges. To maintain logistical economics most barge           barges at a $25/ton rate or $3.57/bbl from St Louis to Houston
tows are at least carrying 90kbbls as the operating leverage of     added to this is our assumption is a $0.80/bbl tariff from
towboats, timing of transport paired with the barge terminal        Cushing to Patoka for barge transfer, or a total of $4.37/bbl. A
capacity constraints allow for optimal barge economics. The         typical lower Mississippi River linehaul tow would move 15
average crude oil barge holds 15-25kbbl of crude and costs          barges (smaller size than KEX) of 150-200kbbls or 25kbpd
~$3.50/bbl from St Louis, MO to Houston, TX. At these prices        compared to and equivalent 260 rail tank cars or 825 crude
barge transportation is the most economic means of moving           tractor trailers. Barge economics offer the largest cost per bbl




                                                                                                                                30
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                                                                                June 30, 2011
                                                                                Refining & Marketing




advantage over rails and trucks, but their limiting factor is the               Exhibit 61

number of available crude barges and the time that it takes to                  Top Tank Barge Operators
transport. On our estimates, there are approximately 421
crude barges that average in size (we assume 15kbbls) that
makes the total capacity at ~400kbpd of barges that round trip
from St Louis to Houston.

Exhibit 60
Barge, Rail and Truck Comparison
Pipeline equivalent
Pipeline Capacity (bbls)                                              90,000
Equivalent Number of Barges                          3                30,000
Equivalent Number of Rail tank cars                150                   600
Equivalent Number of Truck trailers                470                   191
Barge equivalent
Barge: Typical linehaul tow                         15               450,000
Rail Tank Cars                                     260               156,000
Truck Trailers                                     825               157,979
Fuel equivalent 1 ton/gal                                               miles
Barge                                                                   576
Equivalent Number of Rail tank cars                                     413
Equivalent Number of Truck trailers                                     155
Comparison ($/bbl)
Barge (w/tariff to Patoka)                                              $4.37
Train                                                             $6.58-7.23
Trucks                                                    $5-$8/bbl up to $16


Source: Company data, Morgan Stanley Research estimates


In our opinion, Kirby represents the best consolidated operator
with 112 barges that could move only~100-150kbpd or nearly
25% of the market. With such a fragmented barge market
crude producers or refiners would have to consolidate the
crude barge market and existing towboat fleet to move crude
efficiently on the inland waterways, which is why we believe
that barge movement is a cheap means to move crude, but has
limited ability to completely solve the Cushing bottleneck.                     Source: KEX, Informa Economics, Morgan Stanley Research


                                                                                Other prohibitive factors. Based on our estimates some
                                                                                operators like Marathon move heavy sour crudes from the Gulf
                                                                                into the interior St. Louis market to run at their refineries. This
                                                                                could cause logistics issues on crude quality from tank mixing
                                                                                which could further increase the total amount of crude
                                                                                movement capacity. Although difficult to quantify, another
                                                                                potential issue for barges is the traffic on the rivers and lock
                                                                                systems.




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                                                                    June 30, 2011
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Trucks
Trucks not the solution. Trucking, in our view, is not a            The average lifespan of a liquid trailer is roughly 8-10 years old
solution to move crude out of Cushing. Crude trucking is            and the total number of trailers produced each year in the US is
mainly used to move crude from the wellhead to another              8,000. Trailers take on average 2 months to build with a
logistical platform, pipelines, rails, barges, or to refineries     current backlog of up to 6-7 months at average cost of $50,000.
themselves. Trucks generally move crude on short haul trips         The manufacturers suggested lifespan is 7-8 years for a trailer
that are usually less than 100 miles but in some instances          but the refurbished market obviously has extended the life of
longer distances of up to 300 miles are completed. Current          roughly 1/3 of the market.
trucking rates for short haul trips range from $5-8/bbl whereas
long haul trips greater than 300 miles are $16/bbl. For the most    Although, long haul trips are not the solution to move crude out
part trips longer than 100 miles are uneconomic compared to         of Cushing, short haul trucking will be in greater demand to
rail, barging and pipe. Pricing varies in each region as the main   meet local crude production in the Permian, Niobrara, and
trucking constraints are: 1) labor shortages (truck drivers), 2)    Bakken. One liquid tanker manufacturer reinforced our view on
supply of crude tractor trailers which are the lowest percentage    greater short haul demand, their crude trailers production rates
of all tanker products and 3) operating costs that include fuel,    increased to 55% in 2011 from 12% in 2010 of total liquid
labor time and truck maintenance.                                   trailers produced.

Trucking market overview. We investigated the liquid tractor        Incremental trucking supply will be limited due to
trailer market by speaking with industry experts and trailer        production constraints. Currently, the trucking market has
manufacturers. We determined that the total number of liquid        seen in upsurge in orders since mid-2010 as the economic
trailers in the US market is approximately 90,000 with 10%          recovery continued. Annual increase in backlog have been
designated as crude trailers, the remainder are refined product,    over 100% in each month of 2011, according to ACT research.
chemicals, fracking fluid, water and consumable trailers. On        Backlog growth has outstripped production growth, leading to
average, each trailer holds up to 200 bbls of liquid and truckers   an 8.3 months of backlog of liquid tankers in May 2011 from 5.1
can vary the amount of weight they will carry dependent upon        months in May 2010. We believe the extended time to build a
weather and road conditions since crude oil is denser and           new liquids tanker, especially in consideration of an expiring
weighs more than other liquids. Assuming use of all of the          WTI discount, will likely lead to fewer new orders and little
crude trailers in the US travelling 1200 miles round trip in 4      additional takeaway capacity from trucking.
days would only be 450kbpd.

Exhibit 62
QLTY as a proxy for the liquid trailer market




Source: Company data, Morgan Stanley Research




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                                                                   June 30, 2011
                                                                   Refining & Marketing




Stock Implications: Overweight HOC and FTO (HFC on July 1)
Resuming Coverage on HOC and FTO at Overweight                     Heritage FTO assets have distinctive flexibility to run higher
                                                                   percentage of either light or heavier crudes depending on
HFC offers the best exposure to WTI LLS differentials. We          relative economics. FTO’s Cheyenne Refinery is located in
believe that HOC and FTO offer the most leverage to Mid-Con        close proximity to Niobrara oil shale, which are increasing
differentials namely the dislocation between WTI and LLS. We       volumes provide a another advantaged crude for the company.
value the combined entity, HFC with a total of 24% upside on       As the midstream dynamics evolve, FTO can more easily
our base case and 45% on our out of consensus bull case            change its crude slate and maintains better margin stability
scenario. Although HOC and FTO are currently pricing in            than peers. El Dorado and Cheyenne have distinctive flexibility
nearly $9/bbl of the $15/bbl YTD WTI LLS differential vs. $5/bbl   to run higher percentage of either light or heavier crudes
in our last publication “What’s in the Mid-Con Price” (March 25,   depending on relative economics. As the midstream dynamics
2011), we continue to believe that when storage at Cushing         evolve, El Dorado and Cheyenne can more easily change its
meets full capacity and upstream producers begin to shut in        crude slate and maintains better margin stability than peers.
capacity during mid 2012, HFC will offer investors the best
exposure to record setting $50/bbl differentials that provides     HFC’s Tulsa acquisition and integration benefits
45% upside to current prices.                                      opportunistically timed. The acquisition and combination of
                                                                   Sunoco and Sinclair assets in Tulsa appear quite accretive on
High leverage to Mid-Con differentials drives value. The           purchase price. The combined facilities are the closest refiners
merged entity offers direct exposure to the PADD 2 and 4           to Cushing, enjoying the benefits of relatively discounted
markets with assets located in Wyoming, Kansas, New Mexico,        crudes. The integration is on schedule for completion this
Oklahoma and Utah all of which benefit from not only WTI but       summer with further integration potentially to improve
local crudes such as Wyoming Sweets, Black Wax, Permian,           operating efficiencies.
WCS, Bakken and Cushing Grades.
                                                                   UNEV opportunity provides upside. We expect UNEV, a
HFC offers nearly $40mm of cost synergies or and                   406-mile pipeline that will run product from Salt Lake to Las
additional $2/sh. We believe that the newly merged HFC will        Vegas Nevada, to be on-line in spring/summer 2011 with
offer investors additional upside when the nearly $40mm of         service in late 2011. The pipeline will move refined product
SG&A and other corporate expenses are removed. On a                from Salt Lake City into the higher-priced Las Vegas market.
conservative valuation we believe that the $40mm of synergies      We view the pipeline as similar to owning a 24kbpd California
could add an additional $200mm or ~$2/sh, based on 5x              refinery for HFC as it will smooth out seasonality for HFC’s
multiple of EBITDA. We also see additional operational             Wood Cross Salt Lake City refinery and provide some arbitrage
synergies that exist within the refining complex as a whole. As    by taking advantage of higher Las Vegas gasoline prices.
we noted early the relative asset locations within PADD 2 and 4
offer a diverse network that are linked via numerous product       MLP opportunity in asset sales potential. Similar to upside
and crude pipelines allowing for a holistic refining system much   we saw in TSO and MRO, FTO has potential to monetize
like that of Marathon Petroleum. Refined products such as          midstream assets via HEP, HFC’s MLP.
vacuum gas oil, unfinished naphtha, heavy bottoms and
                                                                   Risks to our call: Our call is earnings driven and predicated
residual fuel oils could shipped from various locations like
                                                                   on structurally wider differentials in the Mid-con.
Tulsa to El Dorado to upgrade or meet other product shortfalls.
                                                                   Announcement of major pipeline reversals, or sell-off in
The UNEV pipeline offers increased volumes during winter
                                                                   currently record wide differentials represent headline risk,
months to move and backfill products from Cheyenne and El
                                                                   lower than forecasted US and Canadian liquid production and
Dorado to the Salt Lake and Eastern Washington markets thus
                                                                   risk differentials revert to historical levels (transport).
freeing up increased volumes to move from Salt Lake (Woods
Cross) to the southern Utah and Las Vegas markets.




                                                                                                                               33
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                                                                                                    June 30, 2011
                                                                                                    Refining & Marketing




Holly Corp. (HOC, $68, Overweight, Price Target $84)
Risk Reward View: High Exposure to Mid-Con Refining                                                                                             Investment Thesis
                                                                                                                                                • Strong advantages in both crude
    $120

                                                                                                                                                  slates and niche markets (Rockies
     100                                                                                                   $98 (+44%)                             and Southwest) drive premium
                                                                                                                                                  returns and multiple, and recent
                                                                                                        $84.00 (+23%)
        80                                                                                                                                        integration of the Tulsa refinery adds
                                                                               $ 68.18
                                                                                                                                                  further benefit.
                                                                                                             $64 (-6%)
        60                                                                                                                                      • Advantaged crude slate runs all WTI
                                                                                                                                                  and WTI-linked crude slate (WTS,
        40                                                                                                                                        WCS, and Black Wax crude oils).
                                                                                                                                                • MLP Holly Energy Partners (HEP),
        20                                                                                                                                        41% owned by HOC, and GP 100%
                                                                                                                                                  owned by HOC with IDRs providing
        0
                                                                                                                                                  stable and growing income,
        Jun-09              Dec-09         Jun-10            Dec-10            Jun-11             Dec-11                     Jun-12               increasing support on top of strong
             Price Target (Jun-12)             Historical Stock Performance                 Current Stock Price
                                                                                                              W ARNINGDONOTEDIT_RRS4RL~HOC.N~
                                                                                                                                                  refining in 2011.
Source: FactSet, Morgan Stanley Research
                                                                                                                                                Potential Catalysts
 Price Target $84                        Derived from our base case.
                                                                                                                                                • Start up of the UNEV pipeline drive
 Bull          10% increase in     Shut-in Production Drives wider WTI-LLS ($50/bbl WTI-LLS)
 Case          base crack scenario Utilization: 2 pct. pt. improvement vs. base case.
                                                                                                                                                  margin improvement into 2011 and
 $98                               MC 3:2:1: WTI = $23/bbl (base). WTI-LLS Spread: $50/bbl                                                        rebalance Salt Lake market.
                                   Capital upgrades generate significant incremental returns.                                                   • Higher realized margin benefit from
 Base          6.4x 2011E stub           Crude benefit through mid-2013; Local market strength                                                    WTI-linked crudes vs. waterborne
 Case          EV/EBITDA; DCF            Utilization: 86%.                                                                                        crudes.
 $84           of WTI-LLS Benefit        MC 3:2:1: WTI 2011 = $23/bbl. WTI-LLS Spread: $15/bbl
                                                                                                                                                • Higher product sales into the Las
                                         Valuation implies 11x HEP and 5x HOC stub EBITDA.
                                                                                                                                                  Vegas/California market increase
 Bear          15% decrease in     Faster Pipeline Reversal and Weak Differentials in 2012                                                        margin realizations and reduce
 Case          base crack scenario Utilization: 2 pct. pt. decrease vs. base case.
                                                                                                                                                  seasonality.
 $64                               MC 3:2:1: WTI 2011 = $15/bbl. WTI-LLS Spread: $7/bbl
                                                                                                                                                • Improved operating efficiencies at
Bear to Bull                                                                                                                                      combined Tulsa refineries.
 110
                                                                                            10.00                                               Risks
                                                                              4.00
  90                            15.00
                                            5.00                                                              98                                • Pipeline reversals occur more quickly
                                                                                              0                                                   than expected, eliminating
                                                             84                0
  70                                          0                                                                                                   WTI-linked vs. waterborne crude
                 64                  0
                                                                                                                                                  differentials and Mid-Con benefits.
  50
                                                                                                                                                • Further project delays of UNEV
                                                                                                                                                  pipeline and cost overruns delay
  30
                                                                                                                                                  ability to transport crude into Las
                                                                                                                                                  Vegas during winter months and
  10
                                                                                                                                                  reduced free cash flow.
  -10        Bear Case        WTI-LLS    Heavy-Light     Base Case          Margin       WTI-LLS Bull      Bull Case                            • HOC also has only three refineries,
                              Benefit      Spread                        Improvement        Case
                                                                                                                                                  so any unplanned outage at any
Source: Morgan Stanley Research
                                                                                                                                                  location represents a risk.
                                                                                                                                                • Slower integration of Tulsa refinery
                                                                                                                                                  reduces operational efficiency.




                                                                                                                                                                                        34
                                                                                                       MORGAN                           STANLEY      RESEARCH

                                                                                                       June 30, 2011
                                                                                                       Refining & Marketing




Frontier (FTO, $33, Overweight, Price Target $40)
Risk Reward View: High Exposure to Mid-Con Refining                                                                                               Investment Thesis
                                                                                                                                                  • Premium location of refineries with
 $50
                                                                                                               $47 (+43%)
  45                                                                                                                                                Cheyenne located on the growing
  40                                                                                                        $40.00 (+22%)                           Niobrara unconventional liquids play
                                                                                                                                                    and El Dorado located near Cushing
  35                                                                              $ 32.76
                                                                                                                                                    and major pipelines (Spearhead).
                                                                                                                $31 (-5%)
  30
                                                                                                                                                  • Advantaged crude slate runs all WTI
  25                                                                                                                                                and WTI-linked crude slate (WTS
  20                                                                                                                                                and WCS crude oils).
  15                                                                                                                                              • High relative complexity, access to
                                                                                                                                                    multiple types of crude and premium
  10
                                                                                                                                                    growth markets support ability to
    5                                                                                                                                               generate earnings.
   0                                                                                                                                              • Proximity to Canadian barrels will
   Jun-09              Dec-09             Jun-10               Dec-10             Jun-11           Dec-11                      Jun-12
                                                                                                                                                    drive relative advantage vs. Gulf
            Price Target (Jun-12)                  Historical Stock Performance               Current Stock PriceWARNINGDONOTEDIT_RRS4RL~FTO.N~


                                                                                                                                                    Coast competition ($3-4/bbl
Source: FactSet, Morgan Stanley Research
                                                                                                                                                    advantage in transport cost).
 Price Target $40                       Derived from our base case.
                                                                                                                                                  • Lowest leverage of its peers and
 Bull         Bull Case      Shut-in Production Drives wider WTI-LLS ($50/bbl WTI-LLS)
                                                                                                                                                    $685MM in cash provide plenty of
 Case         Commodity Deck Utilization: 2 pct. pt. improvement vs. base case.
 $47                         MC 3:2:1: WTI = $23/bbl (base). WTI-LLS Spread: $50/bbl
                                                                                                                                                    financial flexibility and strength.
                             Bull Case on Mid-Con refining and heavy differential drive additional                                                Potential Catalysts
                             strong cash flow.
                                                                                                                                                  • Acquisition of a refining asset could
 Base         3.5x 2011E total          Crude benefit through mid-2013; Local market strength
                                                                                                                                                    be a positive or negative catalyst,
 Case         EV/EBITDA                 MC 3:2:1: WTI 2011 = $21.50/bbl. WTI-LLS Spread: $15/bbl
                                                                                                                                                    depending on the asset and the price
 $40                                    Valuation implies 5.0x 2011 stub EBITDA and DCF of WTI Benefit
                                                                                                                                                    paid.
 Bear         Bear Case      Faster Pipeline Reversal and Weak Differentials in 2012
                                                                                                                                                  • Higher realized margin benefit from
 Case         Commodity Deck Utilization: 2 pct. pt. decrease vs. base case.
                                                                                                                                                    WTI-linked crudes vs. waterborne
 $31                         MC 3:2:1: WTI 2011 = $15/bbl. WTI-LLS Spread: $7/bbl.
                                                                                                                                                    crudes.
Bear to Bull                                                                                                                                      • Special dividend to shareholders.
 50                                                                                            2.00
                                                                                  5.00
 45                                                                                                                                               Risks
                                            7.00                                                                    47
 40                                                                                              0                                                • Pipeline reversals occur more quickly
                              2.00                               40                0
 35                                                                                                                                                 than expected, eliminating
 30                                            0                                                                                                    WTI-linked vs. waterborne crude
              31                0
 25
                                                                                                                                                    differentials and Mid-Con benefits.
 20
 15                                                                                                                                               • Double E and Keystone XL pipelines
 10                                                                                                                                                 come online earlier than expected
  5                                                                                                                                                 pressuring both WTI and heavy
  0                                                                                                                                                 differentials.
        Bear Case         Heavy-Light      WTI-LLS           Base Case         WTI-LLS       Heavy-Sour        Bull Case
                            Spread         Benefit                            Differential   +$1.00/bbl                                           • FTO also has only two refineries, so
                                                                               Widens                                                               any unplanned outage at any
Source: Morgan Stanley Research                                                                                                                     location represents a risk.




                                                                                                                                                                                         35
                                                                                                         MORGAN                           STANLEY      RESEARCH

                                                                                                         June 30, 2011
                                                                                                         Refining & Marketing




Western Refining (WNR, $18, Overweight, Price Target $21)
Risk Reward Mid-Con Refining Exposure & Restructuring Upside                                                                                       Investment Thesis
                                                                                                                                                   • Deleveraging story with up to $560MM
    $30


                                                                                                                $26 (+47%)
                                                                                                                                                   of potential asset sales in 2011 to
     25                                                                                                                                            support a capital restructuring, debt
                                                                                                                                                   reduction and removal of covenant
                                                                                                           $21.00 (+19%)
     20
                                                                                 $ 17.63
                                                                                                                                                   heavy, debt obligations.
                                                                                                                                                   • Emerging as a niche refiner in the
     15                                                                                                         $15 (-15%)                         Southwest with ability to run
                                                                                                                                                   WTI/WTI-linked crude slate.
     10                                                                                                                                            • El Paso is a simple refiner with sweet
                                                                                                                                                   crude intake in West Texas near
        5                                                                                                                                          growing Permian Basin crude oil
                                                                                                                                                   production that supports margin-rich
        0                                                                                                                                          markets in Arizona, New Mexico and
        Jun-09            Dec-09           Jun-10           Dec-10                 Jun-11            Dec-11                     Jun-12             Juarez, Mexico.
            Price Target (Jun-12)              Historical Stock Performance                    Current Stock Price
                                                                                                                                                   • Yorktown refinery closure reduces
                                                                                                                  WARNINGDONOTEDIT_RRS4RL~WNR.N~




Source: FactSet, Morgan Stanley Research
                                                                                                                                                   operating costs (loss) and allows for
Price Target $21.00                     Derived from our base case.
                                                                                                                                                   monetization of inventory and potential
 Bull            Bull Commodity         Shut-in Production Drives Wider WTI Differential                                                           MLP of storage and terminal assets.
 Case            Deck                   MC 3:2:1: WTI = $21.50/bbl (base crack). WTI-LLS Spread
 $26                                    widens to $50/bbl
                                                                                                                                                   Potential catalysts
                                                                                                                                                   • Announcement of a formal M&A
 Base            3.4x 2011 total        WTI-LLS Benefit Through mid-2013; Local market strength
                                                                                                                                                   process and ultimate sale of midstream
 Case            EV/EBITDA              MC 3:2:1: WTI 2011 = $21.50/bbl. WTI-LLS Spread: $15/bbl
                                                                                                                                                   assets: (1) Yorktown terminal and
 $21                                    Valuation implies a 4.0x 2011 stub EV/EBITDA (multiple is
                                        compressed due to Mid-Con advantage without Yorktown), DCF                                                 storage, and (2) Southwest terminal,
                                        on WTI differential benefit.                                                                               storage, asphalt terminal and pipelines.
 Bear            Bear Commodity         WTI Differential Narrows
                                                                                                                                                   Potential monetization of inventory.
 Case            Deck                   Utilization: flat vs. base case.                                                                           • Higher realized margin benefit from
 $15                                    MC 3:2:1: WTI 2011 = $13.50/bbl. WTI-LLS spread: $7/bbl                                                    WTI-linked crudes vs. waterborne
                                        Unplanned outages and inability to pay down as WTI differential                                            crudes.
                                        narrows.
                                                                                                                                                   Investment Risks
Bear to Bull
                                                                                                                                                   • Pipeline reversals occur more quickly
   30
                                                                                                                                                   than expected, eliminating WTI-linked
                                                                                              1.00
                                                                              4.00                                                                 vs. waterborne crude differentials and
   25                                                                                                                                              Mid-Con benefits.
                                            5.00                                                0               26
   20                          1.00                                                                                                                • Management fails to execute
                                                            21                 0
                                                                                                                                                   restructuring of the company.
   15
                  15            0             0                                                                                                    • Unplanned refinery outage.
   10
                                                                                                                                                   • Levered balance sheet and high fixed
    5                                                                                                                                              charges lead to potential stress on debt
                                                                                                                                                   covenants.
    0
            Bear Case       Unplanned   Decrease in     Base Case            WTI            Asset Sale        Bull Case
                             Outages        WTI                          Differential
                                        Differential                      Widens


Source: Morgan Stanley Research




                                                                                                                                                                                          36
                                                                                                          MORGAN                            STANLEY   RESEARCH

                                                                                                          June 30, 2011
                                                                                                          Refining & Marketing




Sunoco (SUN, $39, Overweight, Price Target $53)
Risk Reward View: Positive Skew to SOTP Value                                                                                                     Investment Thesis
    $70                                                                                                                                           • SUN is inexpensive on its sum-of
                                                                                                                                                  the parts valuation that will be
     60                                                                                                      $60 (+52%)
                                                                                                                                                  highlighted post SunCoke IPO and
                                                                                                          $53.00 (+35%)                           distribution and payment of significant
     50
                                                                                                                                                  cash dividend to holders. The implied
                                                                                   $ 39.39
     40
                                                                                                                                                  valuation, pro-forma all our estimated
                                                                                                               $37 (-6%)                          distribution, for remaining assets is
     30                                                                                                                                           50% of public peers.
                                                                                                                                                  • SUN will declare a $10-20 per share
     20                                                                                                                                           special dividend in 2H2011.

     10
                                                                                                                                                  • SUN has diverged from its primary
                                                                                                                                                  earnings drivers this year: met coal,
        0                                                                                                                                         logistics, and refining valuations. All
        Jun-09            Dec-09             Jun-10            Dec-10              Jun-11          Dec-11                     Jun-12              drivers are up 10% while SUN is flat.
            Price Target (Jun-12)                 Historical Stock Performance                Current Stock Price
                                                                                                                                                  • SUN mostly considered a NE
                                                                                                                WARNINGDONOTEDIT_RRS4RL~SUN.N~




Source: FactSet, Morgan Stanley Research
                                                                                                                                                  refiner yet its 2012E exposure is less
 Price Target $53                       Derived from our base case.                                                                               than 10% - below most integrated oils
 Bull            Sum of the             Sum of the parts with retail and MLP premium                                                              - and ~85% is levered to growth
 Case            parts                  Sum of the parts valuation Retail at 7.0x EBITDA, Logistics LP units at                                   businesses: Coke, logistics and retail.
 $60                                    public market price, GP at DCF value, SunCoke at 5.9x EBITDA, R&M
                                        at NAV and net cash. Drop down of Eagle Point to MLP.                                                     Potential Catalysts
 Base            Sum of the             Asset sales/separation on schedule at in-line prices                                                      • IPO of SunCoke (equity and debt)
 Case            parts                  Sum of the parts valuation Retail at 7.0x EBITDA, Logistics LP units at                                   and subsequent spin-off.
 $53                                    public market price, GP at DCF value, SunCoke at 5.9x EBITDA and
                                                                                                                                                  • Return of significant portion of
                                        net cash. No value for refining.
                                                                                                                                                  excess cash position to shareholders.
 Bear            Sum of the             Corporate action delayed and sluggish recovery
 Case            parts                  20% discount to sum of the parts valuation. Retail 5.5x EBITDA,                                           • Potential JV, sale, shutdown,
 $37                                    Logistics LP units at market rate, & GP DCF, SunCoke at 5.0x, no                                          liquidation of NE refining.
                                        value for R&M, Chem no value and net cash. No value for refining.                                         • Growth in the MLP business with a
Sum of the Parts Valuation = $60 per share                                                                                                        possible drop down of Eagle Point
                                                                                                                                                  terminals and other M&A
                                                                                                                                                  opportunities in the market.
   60                                                                                              8
                                                                                     6                                                            • Monetization of undervalued GP
                                                                  17
                                                                                                                      60
   50                                                                                                                                             units in SXL.

   40                                                                                0                                                            Risks
                                                  13                                                                                              • Delays in SunCoke IPO and cash
   30
                                                                                                                                                  distribution postpone value unlock.
                                                                   0
   20                               2                                                                                                             • Northeast refining continues to
                 13
                                                                                                                                                  struggle from gasoline imports and
   10
                                    0             0                                                                                               operational issues cause further
    0                                                                                                                                             losses, eroding SUN equity value.
                0
           Marketing @      Eagle Point        Logistics        Coke             Refining @    Net Cash       SOTP Value
                                                                                                                                                  • Company makes a dilutive
           7.0x EBITDA      drop down        LP(Mkt value)    Normalized            NAV
                                              & GP (DCF)       EBITDA                                                                             acquisition with cash proceeds.

Source: Morgan Stanley Research




                                                                                                                                                                                      37
                                                                                                          MORGAN                              STANLEY   RESEARCH

                                                                                                          June 30, 2011
                                                                                                          Refining & Marketing




Valero (VLO, $25, Equal-weight, Price Target $29)
Risk Reward View: Exposed to Global Crude Differentials and Exports                                                                                Investment Thesis
    $35
                                                                                                                                                   • Diversity, size and scale of portfolio,
                                                                                                              $31 (+24%)                           as the largest US Independent refiner,
     30
                                                                                                           $29.00 (+16%)
                                                                                    $ 24.95
                                                                                                                                                   provides leverage to a recovery in
     25                                                                                                                                            global crack spreads and refining.
                                                                                                                $23 (-8%)
                                                                                                                                                   • Complex refining system benefits
     20
                                                                                                                                                   from wider sweet-sour and heavy-light
                                                                                                                                                   differentials with exposure to WTI
     15
                                                                                                                                                   discounts via Mid-Con refining (12%
     10
                                                                                                                                                   capacity) and Maya crude, which has
                                                                                                                                                   linkages to WTI prices.
        5                                                                                                                                          • Gulf Coast refineries able to export
                                                                                                                                                   diesel to Latin America, where strong
        0
        Jun-09            Dec-09             Jun-10           Dec-10                Jun-11          Dec-11                     Jun-12
                                                                                                                                                   demand and refinery issues have led to
            Price Target (Jun-12)                Historical Stock Performance                  Current Stock Price
                                                                                                                 W ARNINGDONOTEDIT_RRS4RL~VLO.N~
                                                                                                                                                   secular growth in distillate imports.
Source: FactSet, Morgan Stanley Research                                                                                                           • Strategic capex spend begins to
 Price Target $29                          Derived from our base case.                                                                             positively impact earnings in 2H 2011,
 Bull            Bull Commodity            Completes Major Capital Improvement Projects                                                            as project improvements are
 Case            Deck                      Utilization: 2 pct. pt. improvement vs. base case.                                                      completed.
 $31                                       GC 3:2:1: Normal = $8.50/bbl. WTI-LLS Spread $50/bbl
                                                                                                                                                   • Acquisition of Pembroke in UK will be
                                           Global demand returns and base crack spreads increase; Heavy
                                                                                                                                                   accretive to earnings and adds
                                           diff = $15/bbl.
                                                                                                                                                   geographic diversification with ability to
 Base            Implied 3.7x 2011         Heavy/Sour Differential Advantage + LatAm Exports Provide
                                                                                                                                                   export distillate product to Europe.
 Case            total EV/EBITDA           Higher returns
 $29                                       GC 2:1:1: 2011 = $7.75/bbl; WTI-LLS Spread: $15; 3.9x stub 2011                                         Potential Catalysts
                                           EBITDA (compressed multiple due to above normal margins
                                                                                                                                                   • Wider crude differentials as loss of
                                           without Mid-Con upside), DCF WTI Benefit.
                                                                                                                                                   Libyan supply leads to wider
 Bear            Bear Commodity            Global Demand Weakens; Differentials Narrow
                                                                                                                                                   heavy-light and sweet-sour differentials
 Case            Deck                      Utilization: 2 pct. pt. decrease vs. base case.
 $23                                       GC 3:2:1: Normal = $8.50/bbl.                                                                           • Stronger global refined product
                                           LatAm demand weakens and additional light, sweet crude (Libya)                                          demand, where VLO has most
                                           narrows heavy-sour differentials.                                                                       exposure to growth of emerging
Bear to Bull                                                                                                                                       markets and export opportunities
   35                                                                              1.00
                                               3.00
                                                                                                 1.00                                              Investment Risks
   30
                                3.00                                                                                 31                            • Narrowing of heavy-light and
                                                                29                   0             0
   25                                                                                                                                              sweet-sour spreads as Libyan supply
                                                 0
                  23                0
                                                                                                                                                   comes back online
   20
                                                                                                                                                   • Latin American demand
   15
                                                                                                                                                   improvements were temporal rather
   10                                                                                                                                              than secular.
    5                                                                                                                                              • Overpays for future acquisition,
                                                                                                                                                   diluting shareholders and weakening
    0
            Bear Case       Heavy-Sour        WTI-LLS       Base Case           Heavy-Sour     WTI-LLS         Bull Case                           existing asset base.
                            Differential      Narrows                           Differential   Widens

Source: Morgan Stanley Research




                                                                                                                                                                                         38
                                                                                                  MORGAN                           STANLEY   RESEARCH

                                                                                                  June 30, 2011
                                                                                                  Refining & Marketing




Tesoro (TSO, $22 Equal-weight, Price Target $25.00)
Risk Reward View: Balanced Risk-Reward Following TLLP IPO                                                                                Investment Thesis
    $30
                                                                                                                                         • Primarily a West Coast refiner with
                                                                                                      $28 (+27%)
                                                                                                                                         five refineries in the region (California,
       25                                                                                          $25.00 (+13%)
                                                                             $ 22.12                                                     Washington, Alaska and Hawaii),
                                                                                                                                         which is more structurally protected
       20                                                                                             $20 (-10%)                         from refined product competition
                                                                                                                                         outside of the region.
       15
                                                                                                                                         • Moderate exposure to Mid-Con
                                                                                                                                         differentials with 17% of operable
       10                                                                                                                                capacity located in Mandan, North
                                                                                                                                         Dakota, and Salt Lake City, Utah.
       5
                                                                                                                                         • TSO’s market is generally isolated
                                                                                                                                         and balanced, offering some amount
       0                                                                                                                                 of protection to even for several
       Jun-09             Dec-09         Jun-10           Dec-10             Jun-11        Dec-11                     Jun-12
             Price Target (Jun-12)            Historical Stock Performance             Current Stock Price
                                                                                                                                         low-quartile assets within TSO’s
                                                                                                        WARNINGDONOTEDIT_RRS4RL~TSO.N~




Source: FactSet, Morgan Stanley Research
                                                                                                                                         portfolio.
 Price Target $25                          Derived from our base case.                                                                   • Potential for further commodity
 Bull           Bull Commodity             California recovery drives higher margins
                                                                                                                                         agnostic benefits in 2011 as
 Case           Deck                       West Coast (WC) 3:2:1 crack spread = $19/bbl, Mid-Con                                         management team reduces costs,
 $28                                       (MC) 3:2:1 crack spread = $27/bbl. Modest unemployment                                        improves operations and attempts to
                                           and transport demand drives 15% margin improvement on                                         restructure Hawaii fuel oil contract to
                                           the West Coast. TLLP Growth provides increased IDR’s.                                         bring back profitability to the refinery.
 Base           Implied 3.7x 2011e         Commodity Agnostic Improvements Coupled With
                                                                                                                                         Potential Catalysts
 Case           total EV/EBITDA            Mid-Con Exposure
 $25                                       2011 WC 3:2:1 = $16.50/bbl; MC 3:2:1 = $23/bbl. 4.0x 2011e                                    • Economic improvement in
                                           stub EBITDA (compressed multiple due to above normal                                          California drives refined product
                                           margins without Mid-Con upside), DCF on WTI Differential                                      demand and higher West Coast crack
                                           Benefit                                                                                       spreads.
 Bear           Bear Commodity             West Coast Weakness Drives Margins Lower                                                      • Further dropdowns into TLLP
 Case           Deck                       Poor WC margins and no Hawaiian PUC re-rate                                                   provide multiple uplift and cash.
 $20                                       California unemployment continues. Corrective California
                                           environmental regulations enforced.
                                                                                                                                         • Hawaii Public Utility Commission
                                                                                                                                         restructures fuel oil contracts.
Bear to Bull
                                                                                           3.00
                                                                                                                                         • Potential Salt Lake and Mandan
  30
                                             2.00
                                                                             2.00                                                        expansions provide Mid-Con benefit
  25                            3.00                                                       0                    28                       Risks
                                                             25               0
  20                                          0                                                                                          • West Coast recovery remains
                20               0                                                                                                       elusive and crack spreads remain
  15
                                                                                                                                         down YoY as unemployment in the
  10                                                                                                                                     region remains high.
   5                                                                                                                                     • No solution to Hawaii PUC contract
                                                                                                                                         with asset continuing to drag on
   0
                                                                                                                                         earnings
            Bear Case      West Coast   WTI-LLS Diff    Base Case         West Coast   WTI-LLS          Bull Case
                            Weakens      Narrows                            Margin     Widens                                            • Harsh environmental regulations in
                                                                         Improvement
                                                                                                                                         California require additional capex
Source: Morgan Stanley Research
                                                                                                                                         investment in refineries.




                                                                                                                                                                               39
                                                                                                         MORGAN                       STANLEY         RESEARCH

                                                                                                         June 30, 2011
                                                                                                         Refining & Marketing




Delek US Holdings (DK, $15, Equal-weight, Price Target $17)
Risk Reward View: Retail Stability With Mid-Con Refining Exposure                                                                                 Investment Thesis
                                                                                                                                                  • Operates a high conversion capacity
    $25

                                                                                                                                                    refinery that meets local demand in
       20                                                                                                       $20 (+34%)                          Tyler, TX and recently completed the
                                                                                                                                                    acquisition of Lion Oil’s El Dorado
                                                                                     $ 14.88
                                                                                                             $17.00 (+14%)                          refinery diversifying its asset base.
                                                                                                                                                  • Largest relative retail exposure of the
       15

                                                                                                                $13 (-13%)
                                                                                                                                                    independent refiners provides
       10                                                                                                                                           earnings stability over time and is
                                                                                                                                                    likely to be expanded post El Dorado
                                                                                                                                                    via connection to the Enterprise
        5                                                                                                                                           pipeline.
                                                                                                                                                  • Currently trading at 4.3x 2011
       0                                                                                                                                            Consensus EV/EBITDA, a ~6%
       Jun-09             Dec-09              Jun-10               Dec-10            Jun-11            Dec-11                  Jun-12               discount to the group.
            Price Target (Jun-12)                 Historical Stock Performance                  Current Stock Price
                                                                                                                                                  • Support at the corporate level by
                                                                                                                  WARNINGDONOTEDIT_RRS4RL~DK.N~




Source: FactSet, Morgan Stanley Research
                                                                                                                                                    Delek Holdings provides clarity for
 Price Target $17                            Derived from our base case.                                                                            future financing needs, along with
 Bull           Bull commodity               Gasoline recovery complements strong retail                                                            60% ownership of all retail real
 Case           deck                         GC 3:2:1: WTI = $11.50/bbl.                                                                            estate.
 $20                                         Strong refining leverage on demand recovery and sour
                                             differential to $3.00/bbl.                                                                           Potential Catalysts
 Base           3.7x 2011E total             Advantageous crude slate and stronger retail                                                         • Additional acquisitions similar to the
 Case           EV/EBITDA; base              Utilization: 90%.                                                                                      El Dorado transaction could fuel
 $17            crack scenario               GC 5:3:2: WTI 2011 = $21.50/bbl. WTI-LLS Spread: $15/bbl.                                              growth and broaden refinery scope.
 Bear           10% decrease in     Weak margins/operational issues                                                                               • Spinout of the retail business could
 Case           base crack scenario Utilization: 2 pct. pt. decrease vs. base case.                                                                 unlock value and use of proceeds
 $13                                GC 3:2:1: WTI 2011 = $13.50/bbl. WTI-LLS Spread: $7/bbl                                                         could help fuel potential M&A.
                                    Operational issues at refining asset impacts earnings.
                                                                                                                                                  • With the El Dorado acquisition
Bear to Bull                                                                                                                                        widening of the sweet-sour spread
 25                                                                                                                                                 would help increase refining
                                                                              1.00              2.00                                                profitability.
 20
                                    4.00                                                                              20                          Risks
 15                                                       17                                                                                      • Engaging in dilutive M&A represents
                                                                                                                                                    a significant risk to DK.
                 13
 10                                                                                                                                               • Continued poor margins in the Gulf
                                                                                                                                                    Coast and narrow sweet-sour
   5                                                                                                                                                spreads produce weak refining
                                                                                                                                                    contribution margins.
   0                                                                                                                                              • Unplanned outages at a single
            Bear Case               Retail             Base Case            Sour WTS       WTI-LLS Benefit       Bull Case
                                                                             Benefit
                                                                                                                                                    refinery can heavily affect earnings..
Source: Morgan Stanley Research




                                                                                                                                                                                       40
                                                                                                         MORGAN                            STANLEY         RESEARCH

                                                                                                         June 30, 2011
                                                                                                         Refining & Marketing




Alon USA US Holdings (ALJ, $11, Underweight, Price Target $11)
Risk Reward View: Retail Stability With Less Refining Upside                                                                                           Investment Thesis
    $16                                                                                                                                                • Operate refineries in Southwest,
                                                                                                                                                         West Coast, ands Gulf Coast, which
     14                                                                                                                                                  historically had lower utilization and
                                                                                                                   $13 (+20%)
                                                                                                                                                         profitability than peers.
     12                                                                          $ 10.84
                                                                                                               $11.00 (+1%)                            • Sizeable asphalt segment, highly
     10                                                                                                                                                  leveraged to construction markets
                                                                                                                    $9 (-17%)
                                                                                                                                                         and in downturn since 2006.
        8
                                                                                                                                                       • Net debt to capitalization remains the
        6                                                                                                                                                highest in our coverage combined
                                                                                                                                                         with a challenged earnings outlook
        4
                                                                                                                                                         makes debt reduction unlikely.
        2                                                                                                                                              • Plans to increase utilization at
                                                                                                                                                         California refineries by transporting
        0
        Jun-09            Dec-09              Jun-10           Dec-10            Jun-11               Dec-11                       Jun-12                vacuum gas oil via truck and rail from
            Price Target (Jun-12)                 Historical Stock Performance                   Current Stock Price W ARNINGDONOTEDIT_RRS4RL~ALJ.N~
                                                                                                                                                         paramount refineries to new
Source: FactSet, Morgan Stanley Research                                                                                                                 Bakersfield hydrocracker.
 Price Target $11                            Derived from our base case.                                                                               • Retail’s contribution to earnings is
 Bull            Bull Commodity              Better Operations at Refineries                                                                             positive offset to less profitable
 Case            Deck                        GC 3:2:1: WTI = $11.50/bbl. Operation Improvements at                                                       refining, yet refining exposure brings
 $13                                         Bakersfield, Paramount, and Krotz Springs Refineries                                                        lower valuation (vs. C-store peers).
 Base            4.3x 2011E total            Advantageous crude slate at Big Spring and stronger retail                                                Potential Catalysts
 Case            EV/EBITDA; base             Utilization: 90%.
                                                                                                                                                       • California refining margins weaken
 $11             crack scenario              GC 3:2:1: WTI 2011 = $10.50/bbl. WTI-LLS Spread: $5/bbl.
                                                                                                                                                         and heavy light spreads narrow
                                             5.7x 2011 stub EBITDA, and DCF of WTI-LLS Benefit.
                                                                                                                                                         causing a revaluation of the
 Bear            Bear Commodity              Continued Operation Issues at California and Krotz Springs
                                                                                                                                                         Paramount Facility.
 Case            Deck                        Utilization: 2 pct. pt. decrease vs. base case.
                                                                                                                                                       • Operational issues at refineries and
 $9                                          GC 3:2:1: WTI 2011 = $9.00/bbl.
                                             Operational issues at refining asset impacts earnings.
                                                                                                                                                         continued low utilization leads to
                                                                                                                                                         further refinery losses.
Bear to Bull
                                                                                                                                                       Investment Risks
   14                                                                               1.00
                                                                    1.00                                                                               • The Retail segment remains
   12                                                                                                     13                                             profitable, and a potential IPO could
                                    2.00
   10                                              11                                                                                                    unlock value.
    8             9                                                                                                                                    • Demand increases for asphalt as
    6                                                                                                                                                    potential federal and state stimulus
                                                                                                                                                         spending provides demand in major
    4
                                                                                                                                                         contract markets such as CA and TX.
    2

    0
            Bear Case          Big Spring       Base Case       California and     WTI-LLS             Bull Case
                               Utilization                           Krotz        Differential
                                                                Improvement


Source: Morgan Stanley Research




                                                                                                                                                                                            41
                                                                                 MORGAN        STANLEY           RESEARCH

                                                                                 June 30, 2011
                                                                                 Refining & Marketing




Exhibit 63
List of Mid-Con Refineries
    Company                            PADD State            Location         Crude       Company                                PADD State           Location                 Crude
    Alon USA                              3     Texas        Big Spring       70,000                                               2   Illinois       Robinson                 204,000
    Big West Oil LLC                      4     Utah         Salt Lake City   30,000                                               2   Kentucky       Catlettsburg             226,000
                                                                                          Marathon Petroleum Corp.
                                          2     Indiana      Whiting          384,750                                              2   Michigan       Detroit                  102,000
    BP
                                          2     Ohio         Toledo           152,000                                              2   Ohio           Canton                   78,000
    Chevron Corp.                         4     Utah         Salt Lake City   45,000      Murphy Oil USA Inc.                      2   Wisconsin      Superior                 33,250
    CHS Inc.                              4     Montana      Laurel           59,600      National Cooperative Refining Assoc.     2   Kansas         McPherson                82,700
    Citgo Petroleum Corp.                 2     Illinois     Lemont           158,650     Northern Tier                            2   Minnesota      St. Paul Park            74,000
    CVR Energy                            2     Kansas       Coffeyville      114,000     PBF holding                              2   Ohio           Toledo                   170,000
                                          2     Oklahoma     Ponca City       187,000     Silver Eagle Refining Inc.               4   Utah           Woods Cross              12,500
    ConocoPhillips
                                          4     Montana      Billings         58,000      Sinclair / Little America                4   Wyoming        Casper                   22,500
    Countrymark Cooperative Inc.          2     Indiana      Mount Vernon     26,500                                               2   Oklahoma       Tulsa                    75,000
                                                                                          Sinclair Oil Corp.
    Delek Refining                        3     Texas        Tyler            60,000                                               4   Wyoming        Sinclair                 66,000
                                          2     Illinois     Joliet           238,000     Suncor Energy                            4   Colorado       Commerce City/Denver     93,000
    ExxonMobil
                                          4     Montana      Billings         60,000                                               4   North Dakota Mandan                     58,000
                                                                                          Tesoro Corp.
    Flint Hills Resources                 2     Minnesota    Rosemount        322,050                                              4   Utah           Salt Lake City           60,000
                                          2     Kansas       El Dorado        135,000     Valero Energy Corp.                      2   Oklahoma       Ardmore                  91,500
    Frontier Oil Corp.
                                          4     Wyoming      Cheyenne         52,000                                               3   New Mexico     Gallup                   23,000
                                                                                          Western Refining
                                          2     Oklahoma     Tulsa            85,000                                               3   Texas          El Paso                  125,000
    Holly Corp.                           3     New Mexico   Artesia          100,000                                              2   Illinois       Wood River               306,000
                                                                                          WRB Refining LLC
                                          4     Utah         Woods Cross      29,450                                               3   Texas          Borger                   146,000
    Husky Energy Corp.                    2     Ohio         Lima             161,500                                              2   Oklahoma       Wynnewood                52,500
                                                                                          Wynnewood Refining Co.
    Montana Refining Co.                  4     Montana      Great Falls       9,500                                               4   Wyoming        Newcastle                12,500
                                                                                                                                                          Total Mid-Con Crude 4,651,450
                                                                                                                                                  Less Capline and MRO Pipes    751,036
                                                                                                                                                                       TOTAL 3,900,414
Source: Company data, Morgan Stanley Research




                                                                                                                                                         42
                                                                                        MORGAN        STANLEY        RESEARCH

                                                                                        June 30, 2011
                                                                                        Refining & Marketing




Exhibit 64
US Refining and Marketing Comparable Metrics
                                                                       Ratings and Capitalization
                   6/29/2011                    Price          Equity Enterprise    Div.           Net Debt / Cap           Net Refining Margin / Barrel
                        Price       Rating     Target           Value    Value     Yield       2010E    2011E     2012E        2010E     2011E      2012E
   VLO                $24.95         E         $29.00          14,222   19,225     0.8%          25%      14%        3%        $3.54     $5.89      $7.01
   TSO                $22.12         E         $26.00           3,176     4,523    0.0%          30%      16%        1%        $3.40     $6.82      $7.37
   SUN                $41.21         O         $53.00           4,991     6,688    1.5%          36%      37%       30%       ($0.20)    $0.35      $1.51
   WNR                $17.63         O         $21.00           1,570     2,580    0.0%          60%      39%       11%        $3.53    $15.08     $14.36
   ALJ                $10.84         U         $11.00             601     1,485    1.5%          75%      61%       43%       ($2.15)    $6.15      $5.76
   HOC                $68.18         O         $84.00           3,635     4,301    0.9%          63%      42%       17%        $2.44    $10.47     $11.02
   FTO                $32.76         O         $40.00           3,487     3,279    0.7%         -27%    -106%     -193%        $3.58    $15.85     $15.58
   DK                 $14.88         E         $17.00             810     1,057    1.0%          36%      12%      -14%        $1.44    $11.02     $11.19
   Average                                                                         0.8%          43%      30%       12%        $1.60     $7.55      $7.87

                                                                                Operations
                     Refining Capacity (mbpd)                      Utilization Rate             $ Gross Margin / Barrel           $ Opex / Barrel
                      2010E      2011E     2012E               2010E      2011E     2012E      2010E     2011E     2012E      2010E   2011E       2012E
   VLO                2,780      2,595     2,595                 77%        85%       86%       $7.80     $9.99    $11.21     $4.26   $4.10       $4.21
   TSO                   665       665       665                 72%        85%       86%      $11.27   $12.91     $13.22     $7.87   $6.09       $5.86
   SUN                   675       505       505                 96%        89%       93%       $5.04     $5.13     $5.76     $5.24   $4.77       $4.25
   WNR                   151       153       154                138%        93%       97%       $8.88   $20.58     $19.75     $5.34   $5.50       $5.39
   ALJ                   247       247       247                 43%        58%       74%       $5.06   $11.64     $11.03     $7.20   $5.48       $5.27
   HOC                   256       256       256                 89%        90%       93%       $7.85   $15.99     $16.27     $5.42   $5.53       $5.25
   FTO                   182       182       182                 93%        96%       99%       $7.86   $20.18     $19.84     $4.28   $4.33       $4.26
   DK                     60        60        60                 90%        95%       94%       $7.00   $16.59     $16.60     $5.56   $5.57       $5.41
   Average                                                       86%        84%       88%       $7.51   $12.80     $12.93     $5.91   $5.25       $5.06

                                                                                Valuation
                         Price / Earnings                       Price / Cons Earnings               EV / EBITDA                 EV / Cons EBITDA
                       2010E     2011E    2012E                2010E     2011E     2012E       2010E     2011E  2012E         2010E    2011E   2012E
   VLO                  17.0x      5.9x     5.9x                15.4x      6.9x      6.6x        5.9x      3.4x   3.1x          5.7x     3.8x    3.6x
   TSO                   NM        6.6x     6.0x                  NM       7.0x      8.1x        8.6x      3.2x   2.8x          8.3x     3.4x    3.6x
   SUN                  21.0x     31.1x    12.6x                23.0x     63.0x     18.0x        5.4x      7.0x   5.4x          6.7x     8.4x    6.8x
   WNR                   NM        4.0x     3.4x                  NM       6.6x      7.2x       10.0x      3.4x   3.3x          9.9x     4.0x    4.3x
   ALJ                   NM        5.1x     3.7x                  NM      15.1x     10.4x        NM        4.2x   3.6x           NM      5.6x    5.2x
   HOC                  35.0x      6.1x     5.4x                35.1x     10.0x     10.9x       11.3x      4.0x   3.8x         11.5x     5.0x    4.5x
   FTO                  92.3x     11.1x    12.4x                91.0x      8.4x     10.6x       17.4x      3.2x   3.1x         18.2x     4.5x    5.1x
   DK                    NM        6.3x     5.5x                  NM      11.3x     15.3x       15.9x      3.8x   3.5x         16.2x     4.9x    5.7x
   Average              19.0x      9.8x     6.2x                19.2x     18.3x     10.9x        9.2x      4.2x   3.6x          9.4x     5.0x    4.9x

                                                                   Morgan Stanley Versus Consensus
                        MS EPS Estimates                       Consensus EPS Estimate          MS EBITDA ($MM)               Consensus EBITDA ($MM)
                       2010E   2011E     2012E                  2010E   2011E     2012E     2010E    2011E   2012E            2010E    2011E    2012E
   VLO                 $1.47   $4.16     $4.20                  $1.62   $3.61     $3.75      3,258    5,629   6,157            3,352    5,009    5,270
   TSO                ($0.33)  $3.30     $3.66                 ($0.29)  $3.15     $2.74        524    1,430   1,637              543    1,343    1,241
   SUN                 $1.98   $1.33     $3.27                  $1.79   $0.65     $2.29      1,229      951   1,239              999      796      986
   WNR                ($0.05)  $4.40     $5.19                 ($0.11)  $2.65     $2.45        257      756     791              260      638      598
   ALJ                ($2.48)  $2.08     $2.90                 ($2.41)  $0.72     $1.04        -51      350     415              -41      266      283
   HOC                 $1.94  $11.06    $12.55                  $1.94   $6.82     $6.25        381    1,083   1,122              373      868      946
   FTO                 $0.36   $2.93     $2.62                  $0.36   $3.89     $3.08        189    1,032   1,041              180      722      641
   DK                 ($0.36)  $2.35     $2.66                 ($0.36)  $1.31     $0.97         66      279     300               65      216      185
Source: Company data, FactSet, Morgan Stanley Research estimates




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Morgan Stanley is currently acting as financial advisor to Marathon Oil Corporation ("Marathon") with respect to the proposed spin-off
of its downstream business as announced on January 13th, 2011. The spin-off is subject to regulatory approvals and other customary
closing conditions. Marathon has agreed to pay fees to Morgan Stanley for its financial advisory services, including transaction fees
and financing fees that are contingent upon the consummation of the proposed spin-off.


Morgan Stanley is acting as financial advisor to Holly Corporation ("Holly") in relation to the proposed merger with Frontier Oil
Corporation ("Frontier"), as announced on February 22, 2011. The proposed transaction is subject to the approval of Holly and
Frontier shareholders, regulatory approvals, and other customary closing conditions. This report and the information provided herein
is not intended to (i) provide voting advice, (ii) serve as an endorsement of the proposed transaction, or (iii) result in the procurement,
withholding or revocation of a proxy or any other action by a security holder. Holly has agreed to pay fees to Morgan Stanley for its
financial services, including transaction fees that are contingent upon the consummation of the proposed transaction




Morgan Stanley is acting as financial advisor to the Audit, Conflicts and Governance Committee (the "ACG Committee") of the board
of directors of DEP Holdings, LLC, the general partner of Duncan Energy Partners L.P. ("Duncan Energy Partners"), in relation to the
proposal from Enterprise Products Partners L.P ("Enterprise Products Partners"), announced on February 23, 2011, to acquire
through a unit-for-unit exchange, all of the outstanding publicly-held common units of Duncan Energy Partners not currently owned by
Enterprise Product Partners.

The proposal is being considered by the ACG Committee.

Duncan Energy Partners has agreed to pay fees to Morgan Stanley for its financial services, including transaction fees, subject to the
consummation of any transaction growing out of the proposal. Please refer to the notes at the end of the report.

Please refer to the notes at the end of the report.




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                                                       Disclosure Section
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Oil Corporation, Occidental Petroleum, Tesoro Corp, Valero Energy Corporation, Western Refining Inc..
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                                                                                              Refining & Marketing




                              Coverage Universe    Investment Banking Clients (IBC)
                                             % of                   % of % of Rating
Stock Rating Category            Count       Total     Count Total IBC Category
Overweight/Buy                   1153           41%            464         48%           40%
Equal-weight/Hold                1140           41%            365         38%           32%
Not-Rated/Hold                     108            4%            20           2%          19%
Underweight/Sell                   390          14%            108         11%           28%
Total                           2,791                          957

Data include common stock and ADRs currently assigned ratings. An investor's decision to buy or sell a stock should depend on individual
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                                                                                                                                                                            47
                                                                                       MORGAN    STANLEY            RESEARCH




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Industry Coverage:Refining & Marketing

Company (Ticker)                              Rating (as of) Price* (06/29/2011)


Evan Calio
Alon USA Energy, Inc. (ALJ.N)                U (10/15/2009)                   $10.84
Delek US Holdings Inc (DK.N)                 E (02/02/2011)                   $14.88
Frontier Oil Corporation (FTO.N)             O (06/30/2011)                   $32.76
Holly Corporation (HOC.N)                    O (06/30/2011)                   $68.18
Sunoco, Inc. (SUN.N)                         O (10/15/2009)                   $41.21
Tesoro Corp (TSO.N)                          E (03/15/2011)                   $22.12
Valero Energy Corporation (VLO.N)            E (10/15/2009)                   $24.95
Western Refining Inc. (WNR.N)                O (10/13/2010)                   $17.63

Stock Ratings are subject to change. Please see latest research for each company.
* Historical prices are not split adjusted.




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