[Senate Hearing 113-71]
[From the U.S. Government Publishing Office]






                                                         S. Hrg. 113-71

                               GAS PRICES

=======================================================================

                                HEARING

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                    ONE HUNDRED THIRTEENTH CONGRESS

                             FIRST SESSION

                                   TO

  EXPLORE HOW U.S. GASOLINE AND FUEL PRICES ARE BEING AFFECTED BY THE 
 CURRENT BOOM IN DOMESTIC OIL PRODUCTION AND THE RESTRUCTURING OF THE 
             U.S. REFINING INDUSTRY AND DISTRIBUTION SYSTEM

                               __________

                             JULY 16, 2013





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               COMMITTEE ON ENERGY AND NATURAL RESOURCES

                      RON WYDEN, Oregon, Chairman

TIM JOHNSON, South Dakota            LISA MURKOWSKI, Alaska
MARY L. LANDRIEU, Louisiana          JOHN BARRASSO, Wyoming
MARIA CANTWELL, Washington           JAMES E. RISCH, Idaho
BERNARD SANDERS, Vermont             MIKE LEE, Utah
DEBBIE STABENOW, Michigan            DEAN HELLER, Nevada
MARK UDALL, Colorado                 JEFF FLAKE, Arizona
AL FRANKEN, Minnesota                TIM SCOTT, South Carolina
JOE MANCHIN, III, West Virginia      LAMAR ALEXANDER, Tennessee
BRIAN SCHATZ, Hawaii                 ROB PORTMAN, Ohio
MARTIN HEINRICH, New Mexico          JOHN HOEVEN, North Dakota
TAMMY BALDWIN, Wisconsin

                    Joshua Sheinkman, Staff Director
                      Sam E. Fowler, Chief Counsel
              Karen K. Billups, Republican Staff Director
           Patrick J. McCormick III, Republican Chief Counsel












                            C O N T E N T S

                              ----------                              

                               STATEMENTS

                                                                   Page

Gilligan, Dan, President, Petroleum Marketers Association of 
  America, Arlington, VA.........................................    27
Hume, Jeffrey B., Vice Chairman, Strategic Growth Initiatives, 
  Continental Resources Inc., Oklahoma City, OK..................    12
Khan, Faisal, Managing Director, Citi Research, New York, NY.....    35
Klesse, William R., Chairman of the Board and Chief Executive 
  Officer, Valero Energy Corporation, San Antonio, TX............    17
Murkowski, Hon. Lisa, U.S. Senator From Alaska...................     4
Plaushin, Chris, Director of Federal Relations, AAA Healthrow, FL    32
Sieminski, Adam, Administrator, Energy Information 
  Administration, Department of Energy...........................     6
Wyden, Hon. Ron, U.S. Senator From Oregon........................     1

                                APPENDIX
                               Appendix I

Responses to additional questions................................    59

                              Appendix II

Additional material submitted for the record.....................    77

 
                               GAS PRICES

                              ----------                              


                         TUESDAY, JULY 16, 2013

                               U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
    The committee met, pursuant to notice, at 10 a.m. in room 
SD-366, Dirksen Senate Office Building, Hon. Ron Wyden, 
chairman, presiding.

 OPENING STATEMENT OF HON. RON WYDEN, U.S. SENATOR FROM OREGON

    The Chairman. The committee will come to order.
    I'd like to begin this morning by expressing my thanks to 
each and every member of this committee.
    As of today, this committee has reported 50 pieces of 
legislation, half of the total number of bills that have been 
sent to the floor of the Senate, and I would just like to take 
note of the fact that this doesn't happen by osmosis. This 
stems from the fact that there has been a lot of cooperation, a 
lot of good will on this committee. A number of these bills 
that have come out of this committee are going to resolve 
issues that have been pending for literally decades, and I'm 
going to recognize Senator Murkowski for her statement in a 
moment, but I just want to note that this could not have 
happened without her leadership. I'm especially appreciative of 
Senator Barrasso as well. Note, Senator Baldwin, she's going to 
enjoy her time on this committee, and I just wanted to begin by 
expressing my thanks to my colleagues on both sides of the 
aisle.
    Senator Murkowski. Mr. Chairman.
    The Chairman. Yes, Senator Murkowski.
    Senator Murkowski. If I may interrupt the Chair, which is 
not something that I like to do, but you have brought up, I 
think, a very important reality that here in this committee, we 
are producing, we are working, we are doing the work that 
committees should. As we all know, these are some exceptionally 
tense times right now, here in the U.S. Senate as we try to 
internally resolve some of our rules have impact on not only 
the rules process, but really on the comity--not the comedy, 
but the comity--that goes on within this body, and I think you 
have clearly led by example, saying bipartisanship needs to be 
more than just picking one member from the other side and 
making something happen, and I do hope that we are able to work 
forward a process in this body that allows us to continue the 
work that the people in this country expect us to do, but I 
think we set the example, we set the standard, by as a 
committee, coming together basically doing our work, rolling up 
our sleeves, and doing the task at hand. So I didn't want to 
miss an opportunity to thank you for your leadership in that 
vein, and encouraging a process that has allowed us to be the 
committee that is producing half of the bills that are ready to 
be heard on the Senate floor, so just thank you.
    The Chairman. I thank my colleague and the fact that you 
consistently meet halfway is a huge part of why we've been able 
to do this and I want to express my appreciation.
    Today, the committee is going to look at the changes taking 
place in the U.S. petroleum industry and their impact, not only 
on the oil industry, but more importantly, on the prices that 
our people pay at the pump.
    At the beginning of this Congress, the committee held its 
first hearing on the dramatic changes taking place in the U.S. 
natural gas market due largely to the development of natural 
gas from shale formations.
    Unlike the immediate benefits that American consumers and 
businesses have seen from low natural gas prices, at the 
gasoline pump, it's been pretty much business as usual. While 
the U.S. economy may be benefiting from declining oil imports, 
prices at the pump have remained consistently high.
    For years, a number of representatives in the oil industry 
have told the American people that U.S. gasoline prices are at 
the mercy of world oil prices. That was basically the case 
because of our dependence on imported oil. New oil supplies 
from America have turned that dynamic on its head. Some regions 
of the country like the Midwest that have access to the lowest 
price crude oil have some of the highest refining margins in 
the Nation. Our committee is going to explore on a bipartisan 
basis why so many consumers have not benefited from these new 
lower cost sources of crude oil.
    In addition to the changing natural gas market, our country 
is going through a dramatic shift in oil and gas production. 
Instead of relying on more and more imports, the U.S. oil 
industry is now increasingly focused, in the Energy Information 
Administration's words, on absorbing the significant increases 
in U.S. oil production, including through export of both crude 
and petroleum. Whether it's oil from the Permian basin in Texas 
or the Bakken formation in North Dakota, there are new supplies 
of oil that were simply not part of the energy equation 5 years 
ago.
    Since 2007, when the Congress passed the last major energy 
bill, our country has gone from importing upwards of 60 percent 
of our crude to now importing roughly 40 percent. That is the 
lowest percentage since 1991. The largest source of those 
imports, 28 percent, is Canada. According to the Energy 
Information Administration, this trend is going to continue. 
The Energy Information Administration is project that the U.S. 
will increase crude oil production from a low in 2008 of 5 
million barrels a day to 8.2 million barrels a day by the end 
of next year. That's a 64 percent increase.
    Another trend that the Energy Information Administration 
says is going to continue is the decline in expected U.S. 
gasoline demand, as cars and trucks become more efficient due 
to higher vehicle mileage standards. Ethanol use, required by 
the Renewable Fuel Standard, is also displacing about 10 
percent of the gas in every gallon sold in the country. That 
mandate, the RFS mandate, is going to require even higher 
blends if left unchanged, which should also further diminish 
the demand for oil.
    So we've gone from being a net importer of petroleum 
products to a net exporter of petroleum products for the first 
time in more than half a century. U.S. refineries are now 
exporting over 2.8 million barrels of gas and diesel fuel and 
other petroleum products a day, thanks in large part to access 
to new, cheaper crude oil supplies and abundant low-cost 
natural gas that's used to fuel the refineries.
    The U.S. refining industry clearly has a major competitive 
advantage over other overseas suppliers, especially for markets 
in North, South, and Central America, but many of our people 
want to know why prices are so high here at home when there is 
so much extra gas and diesel fuel that it can actually be 
exported. Our people want to know why the flood of new domestic 
crude hasn't been lowering prices at the pump. Instead, 
refiners in the middle of the country with the greatest access 
to the cheapest crudes have had the highest margins with the 
difference between the cost of the oil they buy and the 
gasoline and diesel fuel they sell often exceeding $40 or $50 a 
barrel. In many cases, these refining margins are now at record 
or near-record levels; some, as I say, over a substantial 
amount a gallon. What's been good for refiners hasn't 
necessarily been good for the consumer.
    Another important development in the U.S. oil and gas 
industry are the structural changes that have taken place. The 
largest refinery in the United States is no longer a major 
integrated oil company; it's an independent refiner, Valero, 
who will be testifying here this morning. Refiners often don't 
own their own distribution terminals. Oil companies no longer 
own their own service stations. The number of oil refineries in 
the country has also declined, though total refining capacity 
is up, making our Nation more dependent on a smaller number of 
larger, more complex refineries. An outage at one of these 
refineries, whether planned or accidental, is now a major 
factor in the price at the pump. Last October, a minor electric 
power outage in a major refinery in California raised wholesale 
gasoline prices over 80 cents a gallon in a matter of hours. In 
the upper Midwest last month, the prices shot up almost--again, 
a substantial amount, in a week as a result of refinery 
outages.
    I want to thank Senator Franken for highlighting this issue 
and for his work with me to strengthen our ability to track 
refinery outages and reduce their impacts on prices to 
consumers, and I want to highlight again, this has been a 
bipartisan concern. Senator Hoeven is a co-sponsor of 
legislation that involves both Senator Klobuchar and Senator 
Franken to look at reporting in this area. Senator Donnelly has 
done very good work on that. They're all from the Midwest and 
they are all seeking to work on an important issue in a 
bipartisan way.
    Today's hearing begins the committee's examination of all 
of the changes in the oil industry that I have tried to touch 
on here and what they mean for consumers. Supply is up, demand 
is down, but prices at the pump are still stubbornly high, and 
sometimes, are as volatile as the gas itself. Some refiners 
have enjoyed record margins, but there's been a lot less joy 
for millions of consumers at the pump.
    We've got a good cross-section of the energy market here 
today. They include a producer, a refiner, representatives of 
marketers and consumers, and 2 independent industry analysts 
who don't have--I guess you'd call it an official dog in the 
fight; one from the government and one from the private sector.
    Mr. Hume is Vice Chairman of Strategic Growth Initiatives 
for Continental Resources, a very large producer in North 
Dakota. Mr. Klesse is the Chairman and CEO of Valero. Mr. 
Gilligan is the President of Petroleum Marketers Association. 
Mr. Plaushin is Director of Federal Relations for the AAA. Mr. 
Sieminski is the Administrator of the Energy Information 
Administration at the Department of Energy, and Mr. Khan is 
Managing Director for Integrated Oil & Gas Research at 
Citigroup. So I want to, again, thank my colleagues and 
recognize Senator Murkowski.

        STATEMENT OF HON. LISA MURKOWSKI, U.S. SENATOR 
                          FROM ALASKA

    Senator Murkowski. Thank you, Mr. Chairman.
    I was home in the State over the Fourth of July recess and 
had the opportunity to spend a little bit of time on the 
Kuskokwim River. I was going out looking at, talking to 
individuals in their fish camps about what's happening with 
fishing, price of fuel, and what that means to them in their 
villages, and it was just after the spring barge had come and 
delivered fuel. If you live on the Kuskokwim, you get 2 fuel 
deliveries a year; you get one in the spring, which is June, 
and you get one in September, provided that you can get 
upriver. Sometimes, you can only get one barge in, but 
basically, your price for fuel is set when those purchases are 
made, and everyone in the village--it's not like there's any 
competition out there; it is what it is--and when you're in 
Bethel, which is the big hub community, paying over $5 a gallon 
for your fuel, when the barge comes in, you're hoping that it's 
going to go down. The prices didn't go down, they went up 20 
cents, so on Monday, you're sitting at $5.15 and on Tuesday, 
you're sitting at $5.35 for the balance of the summer with no 
relief in sight.
    You go upriver to Aniak and they were hit with a 20-cent 
increase in their fuel for the summer. You go 10 miles upriver 
to Chuathbaluk and there's no fuel; there is just no fuel. You 
want fuel for your boat, you borrow some fuel from your 
neighbor and you go downriver to Aniak and it's about a $50 run 
for that 10 miles.
    So in my home State, when we're talking about gas prices, 
it's real, it's immediate, it directs and it dictates how you 
live and what it is that you do. So I appreciate the 
opportunity for good discussion on this and really, how we deal 
with this from a policy perspective.
    I appreciate, Mr. Chairman, your approach on the basic 
structure for this hearing. I'm optimistic that our decision to 
look not just at gasoline prices, but a whole range of factors 
that could be influencing them, will be helpful to us in our 
policymaking options.
    Let me also welcome our distinguished panel this morning. I 
know you will provide us with valuable perspective on what it 
takes to recover, to refine, and to retail our Nation's 
transportation fuels.
    It's hard to believe that it's now been 5 years, almost to 
the day, Mr. Chairman, since the price of oil rose to an all-
time high of $147 a barrel. We're down from that, thankfully, 
but still, $147 a barrel 5 years ago; it's almost equally hard 
to believe how much has changed since then. One of the 
brightest spots in our entire economy has been and continues to 
be energy production on State and on private lands. After years 
of listening to critics contend that the U.S. is running out of 
oil, domestic production has risen by 30 percent over these 
past 5 years, it's created thousands and thousands of jobs, 
generated substantial revenues, slashed our OPEC imports. 
According to a recent analysis by the Wall Street Journal, it 
has helped reduce volatility in world oil prices and while it's 
difficult to measure the precise benefit, I believe that rising 
American production has reduced, or at the very least, 
restrained some of what we're seeing in terms of prices at the 
pump. One downside is that production on Federal lands has not 
kept pace; it actually fell in both 2011 and 2012, and I think 
that that represents a huge missed opportunity, and all you 
need to do is look to my State of Alaska. We've got more 
untapped oil than any other State, we've got broad public 
support for new production, we've got a major pipeline that is 
sitting at less than half full; all we're asking for is 
permission to produce our resources, but we haven't been able 
to secure that at this point in time.
    Now outside of production, I think there are some other 
factors that are worthy of consideration. I look forward to 
discussion of transportation and infrastructure constraints and 
learning what we can do to help resolve those. I'm glad we're 
going to have a chance to hear about the importance of a robust 
refining sector, I'm eager to examine some of the regulations 
that could be impacting our fuel supply, particularly the 
Renewable Fuel Standards, which I think that Congress needs to 
reform.
    Mr. Chairman, I continue to believe that we need to take 
every step possible to reduce and stabilize fuel prices for 
American families and for our businesses, but that's going to 
include increasing production on Federal lands, increasing the 
efficiency of our vehicles and increasing the use of 
alternatives. It will mean rejecting rather than seeking 
punitive tax hikes, it will require the timely approval of 
needed projects, including the Keystone Excel pipeline, and the 
prompt adjustment of any regulation that comes in conflict with 
our desire for abundant and affordable energy.
    So again, I look forward to the witnesses' testimony here 
this morning and the questions that we'll be able to pose 
afterwards.
    Thank you.
    The Chairman. Thank you, Senator Murkowski, and I think 
it's very important, the point you made, that there are a 
variety of factors that go in to this whole debate. We talked 
about it when we were together in Alaska and I think it's just 
as correct today and I thank you for a very helpful statement.
    For our witnesses, we're probably going to have at least 
one vote at 11, and what happens on a day like this is Senator 
Murkowski and I work together from time to time to call some 
audibles and try to figure out how to keep everything moving, 
and our hope is that we'll be able to do it. So if each of you 
will take 5 minutes or so and highlight your principal 
concerns, we'll make your prepared statements part of the 
record. Why don't we begin with you, Mr. Sieminski?

STATEMENT OF ADAM SIEMINSKI, ADMINISTRATOR, ENERGY INFORMATION 
              ADMINISTRATION, DEPARTMENT OF ENERGY

    Mr. Sieminski. Thank you, Chairman Wyden.
    Right Member Murkowski, members of the committee, thank you 
for the opportunity to appear here today.
    EIA is the statistical and analytical agency at the 
Department of Energy. By law, EIA's data analysis and forecasts 
are independent of approval by any other officer or employee of 
the U.S. Government.
    I'd like to make 5 main points today. First, the United 
States is undergoing a dramatic change in domestic oil product, 
most of which has occurred in the past 3 years. Domestic oil 
output is now at the highest level since October 1992. Texas 
has more than doubled its production and North Dakota's output 
has nearly tripled. The unexpected pace of the growth has 
stressed the petroleum supply infrastructure; notably, a 
dramatic increase in shipments of crude oil by rail from the 
Bakken in North Dakota reflects both lags in adding pipeline 
infrastructure and the flexibility of rail shipments to serve 
coastal refineries. Several pipeline projects are currently 
underway or proposed which should increase deliveries of 
domestic crude oil from inland sources to major refining 
centers, primarily on the Gulf Coast.
    Second, domestic crude oil supplies are growing. Refiners 
face declining demand for gasoline in the U.S. market. Since 
2007, demand for gasoline has dropped by almost 600,000 barrels 
a day and the amount of ethanol being added to the gasoline 
pool has increased supply by almost 400,000 barrels a day. 
Imports of gasoline-blending components have declined and 
exports of refined products, as you noted, Senator Wyden, 
primarily from the Gulf Coast have increased. Infrastructure 
constraints within the U.S. limit the movement of petroleum 
products from refining centers like the Gulf Coast to regions 
where product demand actually exceeds production capacity like 
the Northwest. Product exports provide a way for refining 
centers to optimize crude runs and operations. While virtually 
all of the new production in the U.S. is light sweet crude, 
much of the refining capacity in the Gulf Coast has been 
optimized to run on heavy sour crude. To accommodate the change 
in crude slate, refiners have a number of alternatives ranging 
from little or no-cost projects to major capital investments. 
No matter the cost of the alternative, the ability and extent 
to which it can be accomplished is unique to each refinery and 
cannot be estimated accurately by EIA at this time.
    Third point, in 2012, the United States imported 11 million 
barrels a day of crude oil and refined petroleum products. At 
the same time, the Nation exported 2.7 million barrels a day of 
finished petroleum products and gasoline-blend stocks. While 
most product imports occurred on the East Coast and exports 
from the Gulf Coast, the U.S. as a whole is linked by a very 
complex logistical system which transports products and 
influences prices throughout the country. As with crude, 
refined product prices are heavily influenced by the 
international markets. The U.S. exports a small amount of crude 
oil to Canada; the first 4 months of this year, the volume was 
over 100,000 barrels a day, up from the 2012 average of about 
60,000 barrels a day.
    Fourth point, ethanol, comprising nearly 10 percent of the 
gasoline pool, has to be moved mainly from the Midwest to 
market centers along the East, West and Gulf Coasts where it is 
then blended into the gasoline pool. Short-term fluctuations in 
regional product supply chains can cause prices in particular 
regions of the country to be temporarily disconnected from 
world and national market forces. This spring, 2 unplanned 
refinery outages in the Midwest, along with delayed restarts at 
several others, caused average retail gasoline prices to 
increase by 26 cents a gallon between the end of April and the 
middle of June. Similar price increases occurred in 2012 on the 
West Coast after a series of unplanned outages. These 
occurrences are relatively short-lived, 6 to 8 weeks usually, 
and are the result of largely unforeseeable circumstances.
    Fifth and final point, over the last several years, EIA has 
recognized significant changes to the supply and demand pattern 
and patterns for petroleum products, both domestically and with 
external trade. EIA collects, analyzes and reports more data on 
our national petroleum supply than any other comparable 
organization in the world. As resources have permitted, and in 
some cases, where significant regional transitions have raised 
concerns with Members of Congress, EIA has monitored, analyzed 
and reported on potential market changes.
    This committee is a very important user of EIA's services 
and I look forward to working with you. Thank you.
    [The prepared statement of Mr. Sieminski follows:]

Prepared Statement of Adam Sieminski, Administrator, Energy Information 
                  Administration, Department of Energy
    Chairman Wyden, Ranking Member Murkowski, and Members of the 
Committee, thank you for the opportunity to appear before you today to 
discuss the U.S. petroleum supply system, which is changing rapidly.
    The U.S. Energy Information Administration (EIA) is the statistical 
and analytical agency within the U.S. Department of Energy. EIA 
collects, analyzes, and disseminates independent and impartial energy 
information to promote sound policymaking, efficient markets, and 
public understanding regarding energy and its interaction with the 
economy and the environment. By law, EIA's data, analyses, and 
forecasts are independent of approval by any other officer or employee 
of the United States Government, so the views expressed herein should 
not be construed as representing those of the Department of Energy or 
any other Federal agency. As discussed in my testimony, EIA is active 
in providing both data and analysis that bear directly on supplies of 
petroleum products in this country. The main points of my testimony are 
as follows:
    The United States is undergoing a dramatic change in domestic oil 
production. The rate of increase in domestic production continues to 
surpass even the most optimistic forecasts of recent years. Domestic 
oil production in the United States has increased significantly, and at 
7.4 million barrels per day as of April 2013 is now at the highest 
level since October 1992. Over the five year period through calendar 
year 2012, domestic oil production increased by 1.5 million barrels per 
day, or 30 percent. Most of that growth occurred over the past 3 years. 
Lower 48 onshore production (total U.S. Lower 48 production minus 
production from the federal Gulf of Mexico and federal Pacific) rose 
more than 2 million barrels per day (bbl/d), or 64 percent, between 
February 2010 and February 2013, primarily because of a rise in 
productivity from oil-bearing, low-permeability rocks. Texas more than 
doubled its production and North Dakota's output nearly tripled over 
that period. Five western states--Oklahoma, New Mexico, Wyoming, 
Colorado, and Utah-had production increases ranging from 23 percent to 
64 percent over the same three years. This rapid growth has stressed 
many parts of the U.S. petroleum supply infrastructure.
    Currently, transportation constraints are limiting the full impact 
of increased domestic crude production, but these constraints are 
expected to ease in the coming years. Historically, about 90 percent of 
the crude oil and petroleum products in the United States have been 
transported by pipeline. However, shipments of crude oil by rail from 
North Dakota's Bakken Shale formation have increased dramatically over 
the past year, reflecting both lags in adding pipeline infrastructure 
to transport growing volumes of crude and the ability of rail shipments 
to serve east coast refineries in the United States and Canada and U.S. 
west coast refineries, where Bakken crude has its greatest economic 
value as a replacement for seaborne imports of light sweet crude oil. 
Crude oil and petroleum products shipments by rail averaged 1.37 
million barrels per day during the first half of 2013. (Up 48 percent 
from 927,000 bpd in same period in 2012) according to the Association 
of American Railroads (AAR), which tracks movement of commodities by 
rail. Crude oil accounted for an estimated 50 percent of the combined 
deliveries in the oil and petroleum products, up from 3 percent in 
2009. This topic was discussed in the EIA This Week in Petroleum 
article of July 11 (See Attachment 1*)
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    * All attachments have been retained in committee files.
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    Several pipeline projects are currently under way or proposed which 
should increase deliveries of domestic crude from inland sources to 
major refining centers, primarily on the Gulf Coast. Additionally, as 
discussed in the EIA Today in Energy article of July 10 (See Attachment 
2), more Bakken crude is being moved to market by rail. By addressing 
logistical constraints, these developments are leading to lower 
discounts for inland crudes. Even before these projects, however, 
increasing domestic crude production has reduced crude oil imports by 
almost 1.3 million bpd, or 13 percent, since 2008. Virtually all of the 
reduction in U.S. crude oil imports is reflected in lower imports from 
member countries of the Organization of the Petroleum Exporting 
Countries.
    Currently the U.S. is also a very limited exporter of crude oil. 
Any company wanting to export crude oil must obtain a license from the 
Bureau of Industry and Security (BIS), which is part of the U.S. 
Department of Commerce. According to the regulations published in Title 
15 Part 754.2 of the Code of Federal Regulations, BIS will approve 
applications for licenses to export crude oil for the following kinds 
of transactions:

   From Alaska's Cook Inlet
   To Canada for consumption or use therein
   In connection with refining or exchange of Strategic 
        Petroleum Reserve oil
   Of up to an average of 25,000 bbl/d of California heavy 
        crude oil
   That are consistent with findings made by the president 
        under an applicable statute
   Of foreign-origin crude oil where, based on written 
        documentation satisfactory to BIS, the exporter can demonstrate 
        that the oil is not of U.S. origin and has not been commingled 
        with oil of U.S. origin

    Monthly exports of crude oil from the United States to Canada have 
historically averaged 24,000 barrels per day (bbl/d) and were 
principally delivered to refineries in central Canada. However, U.S. 
exports to Canada averaged over 100,000 bbl/d over the first 4 months 
of 2013 as Canadian refineries, like those in the United States, are 
processing increased volumes of crude oil produced in Texas and North 
Dakota. At the same time as domestic crude oil supplies are growing, 
U.S. refiners face declining demand for gasoline in the U.S. market. 
Since 2007, demand for gasoline in the U.S. has declined by almost 
600,000 bbl/d, or 6.3 percent, and the amount of ethanol being added to 
the gasoline pool has increased by almost 400,000 bbl/d (replacing 
about 270,000 bbl/d of petroleum gasoline after accounting for 
ethanol's lower energy content relative to petroleum gasoline) . 
Therefore, from a crude oil refiner's standpoint, demand for the 
refined portion of gasoline has declined by almost 900,000 bbl/d, which 
is the equivalent output of 14 average sized U.S. refineries. As a 
response, imports of gasoline blending components have declined by 
almost 500,000 bbl/d, or 43 percent, and exports primarily from the 
Gulf Coast, have increased by almost 400,000 bbl/d. In 2012, 84 percent 
of the gasoline exports went to countries in Latin America. In 
addition, diesel demand in the U.S. declined by 450,000 bbl/d in the 
same time period, or by 11 percent, leading to a drop in diesel imports 
of 200,000 bbl/d and increased exports of over 700,000 bbl/d. Again, in 
2012, 61 percent of the diesel exports went to Latin America and 35 
percent to Europe.
    Infrastructure constraints within the United States, including 
pipeline capacity and marine vessel availability, limit the movement of 
petroleum products from U.S. refining centers like the Gulf Coast to 
the Northeast and other regions where product demands far exceeds 
product production capability of within-region refining capacity. 
Product exports provide a way for refining centers to optimize crude 
runs and operations. Although expected increases in domestic demand for 
diesel should reduce future distillate exports, gasoline exports are 
likely to increase. Domestic demand is expected to continue to decline 
due to improvements in the efficiency of new vehicles subject to fuel 
economy standards that grow steadily more stringent through the 2025 
model year as well as the potential increased use of higher-percentage 
ethanol blends and other biofuels to meet the requirements of the 
renewable fuel standards. Access to relatively low cost domestic crude 
oil and natural gas has given U.S. refineries a cost advantage in 
serving foreign product markets compared to refiners located in other 
countries who also compete to serve those markets . While access to 
growing supplies of domestic crude is generally advantageous for U.S. 
refiners, they do face some challenges in changing their input slates 
to accommodate the quality mix of U.S. crude production. Specifically, 
while virtually all of the new crude production in the U.S. is light 
sweet crude, much of the refining capacity in the Gulf Coast is 
optimized to run heavy, sour crude.
    To adapt to increasing supplies of domestic light sweet crude, 
there are a number of alternatives available to refiners that range 
from little or no cost to major capital investments that would only be 
justified by large crude price differentials.
    The low cost alternatives are those which do not meaningfully 
change the average gravity of the crude for which the refinery was 
designed. First of all, refiners can simply utilize unused light crude 
capacity and increase the amount of crude that they run. Since 2008, 
refinery runs have increased and average crude gravity has gone up, 
particularly on the Gulf Coast, indicating that spare light crude 
capacity was being utilized. By 2012, however, U.S. refiners ran at a 
utilization rate of 88.8 percent, the highest level since 2007 and a 
level which many analysts view as effectively full utilization after 
accounting for typicallevels of planned and unplanned outages.
    Second, refiners can simply substitute domestic light sweet crude 
for imported volumes, most of which, according to EIA data, has already 
been accomplished on the Gulf Coast. Refiners on the East and West 
Coasts still import significant amounts of light sweet crude, but with 
rail shipments and eventually pipeline additions, imports can be 
displaced. Lastly for a low cost alternative, refiners can blend more 
light sweet crude with heavier crudes to meet their desired crude 
quality. The ability and extent to which this can be accomplished is 
unique to each refinery and cannot be estimated by EIA at this time.
    Other available options that involve changing the average crude 
quality run at a particular facility away from its typical inputs 
require either operational changes based on short term market 
incentives or capital investments which require longer term incentives. 
Operationally, refiners can run more light sweet crude but at the 
expense of total crude input, a loss that must be incentivized by 
relative crude prices. For longer term capital investments, there are 
two basic alternatives available to refiners. The first, lower cost 
option would be to process light sweet crude to remove its lightest 
components, thereby making it more like medium gravity crude which 
could then be used as a substitute for imported medium crude. The more 
costly approach would be to invest in larger units throughout the 
refinery which deal with lighter components of crude such that light 
sweet crude could substitute for heavy crude. Again, these investments 
are unique to each refinery and are based on individual company 
investment decisions.
    In spite of the dramatic changes in the U.S. petroleum supply 
system, prices of both domestic crude and petroleum products continue 
to be driven by the international market, albeit subject to short term 
fluctuations in the supply chain. The United States continues to rely 
on imported crude oil and petroleum products to meet domestic demand. 
In 2012, the United States imported 11.0 million bbl/d of crude oil and 
refined petroleum products. At the same time, the nation exported 2.7 
million bbl/d of finished petroleum products and gasoline blendstocks 
that are also priced on the international market. While most product 
imports occur on the East Coast and exports from the Gulf Coast, the 
United States as a whole is linked by a complex logistical system which 
transports product and influences prices throughout the country (see 
Figure 1*).
---------------------------------------------------------------------------
    * All figures have been retained in committee files.
---------------------------------------------------------------------------
    The petroleum product supply system has developed over many decades 
to serve demand centers from both local and distant refining centers. 
More recently, an added complexity has resulted from the requirement to 
move ethanol from its predominant Midwest supply region to regions 
throughout the country where it is blended into the gasoline pool (see 
Figure 2*).
    As noted above, short-term fluctuations in regional product supply 
chains can cause prices in a particular region of the country to become 
temporarily disconnected from world and national market forces. This 
spring, two unplanned refinery outages in the Midwest along with 
delayed restarts at several others caused average retail gasoline 
prices to increase by 26 cents per gallon between the end of April and 
the middle of June. The price increase was more dramatic in parts of 
North Dakota and Minnesota but by the end of June, prices had returned 
to a more normal level. Similar price increases occurred in 2012 on the 
West Coast after a series of unplanned outages. While we recognize the 
burden these price increases place on the American public, these 
occurrences are relatively short-lived and are the result of largely 
unforeseeable circumstances.
    EIA remains actively engaged in monitoring and reporting on matters 
related to domestic petroleum product supplies. EIA collects, analyzes, 
and reports more data on our national petroleum supply system than any 
other comparable organization in the world. We access data on where 
crude is produced, what type of crude it is, where it goes, and the 
ultimate slate of refined products. We collect data on product 
movements by pipeline and ship and have an extensive database on crude 
and product imports including the product type and crude quality, the 
importing entity, and the country (and port) of origin. Like any other 
organization covering a rapidly changing industry, we also recognize 
the need for increased data collection and analysis. Over the last 
several years, EIA has recognized significant changes to the supply and 
demand patterns for petroleum products both domestically and with 
external trade. As resources have permitted, and in some cases where 
significant regional transitions have raised concern with Members of 
Congress, EIA has monitored, analyzed and reported on potential market 
changes, including the following:

   U.S. exports of petroleum products
   The proposed sale or closure of three East Coast refineries
   West Coast refinery outages and gasoline price increases
   Possible closure of the Tesoro refinery in Hawaii
   Closure of the Hess Port Reading, NJ refinery
   Midwest refinery outages and gasoline price increases

    We have been developing a system to collect crude production data 
at the well head to better monitor and project domestic crude 
production. EIA is monitoring the following emerging trends in 
transportation and midstream infrastructure: crude shipments by rail, 
barge and truck (see Attachment 1 July 11 This Week in Petroleum 
article), crude oil pipeline capacity additions and reversals, re-
purposing of natural gas pipelines to crude oil and gas liquids 
service, changing availability of coastwise compliant and foreign flag 
vessels. We regularly publish a variety of reports on important 
petroleum supply trends, including This Week In Petroleum, the Short 
Term Energy Outlook and the Annual Energy Outlook. Although EIA has 
followed Atlantic basin petroleum product trade for decades, we are 
currently challenged to keep up with the expanding products trade 
within the Americas and across the Pacific. This Committee is a very 
important customer of the EIA and I would look forward to a discussion 
with you.
    Thank you for the opportunity to testify before the Committee.
                  ATTACHMENT 1--THIS WEEK IN PETROLEUM
       u.s. crude oil increasingly moves by barge, truck and rail
    The U.S. Energy Information Administration (EIA) recently released 
its annual data series tracking how crude oil reaches the refinery 
gate. Not surprisingly, the 2012 data show heightened reliance on crude 
receipts via barge, truck and rail.
    There has been much discussion about the rise in U.S. crude oil 
production and the resulting overhang in inventories at Cushing, 
Oklahoma and elsewhere in the midcontinent because of pipeline 
infrastructure that has not kept pace with burgeoning domestic crude 
oil supply. The supply-pipeline mismatch is encouraging market 
participants to increasingly rely on alternative transportation 
options.
    From 2005 to 2010, 96 percent of refinery crude oil receipts came 
by pipeline and tanker (ship). With relatively low costs and high 
capacity, pipelines have long been the delivery method of choice for 
inland refineries. Coastal refineries, on the other hand, have 
typically been served by tankers of waterborne imports or offshore 
production. In 2011, this usage began to decline, and in 2012, 
pipelines and tankers delivered 93 percent of crude oil processed by 
U.S. refiners (Figure 1*). The balance is made up primarily of domestic 
crude supplies carried via barge, rail and truck. Foreign receipts via 
barge have declined slightly.
    Because truck and rail are less cost-effective options for moving 
crude, they typically have accounted for a very small portion of 
refinery crude receipts, averaging just 1 percent of total receipts 
from 2000 to 2010. Starting in 2011, this truck and rail volume 
increased, and in 2012 it represented 3 percent of refinery receipts. 
Additionally, domestic barge receipts also increased, and now account 
for close to 3 percent (Figure 2*). Expanding existing pipelines or 
building entirely new ones is costly and requires lengthy regulatory 
review. Using trucks and trains on the other hand, provides greater 
flexibility and uses existing infrastructure. As long as the Bakken and 
WTI prices trade at a large enough discount to global, waterborne 
crudes, these transportation patterns are likely to persist or even 
expand.
    EIA collects data on crude delivery methods annually from all U.S. 
refineries. In cases where multiple transportation modes are used, 
respondents report the mode used for the last 100 miles. If several 
modes are used, and none is more than 100 miles, the method 
representing the longest distance is recorded. This may partially 
explain the increase in domestic barge traffic, with crude oil loaded 
on rail cars at production areas and then transferred to barges for the 
final leg of some journeys to refineries, particularly on the East 
Coast and along the Mississippi River. With increased rail traffic 
reported by the Association of American Railroads for the first half of 
2013, it is likely that the EIA data on domestic crude receipts by rail 
will be higher in EIA's 2013 survey.
    In addition to delivering more crude oil to U.S. refineries, 
railroads are shipping U.S. crude oil to eastern Canadian refineries. 
While the Midwest has been the traditional source for U.S. crude oil 
exports to Canada, a recent increase in exports is being led by 
deliveries from the Gulf Coast (waterborne) and the East Coast. The 
exports from the East Coast are primarily barrels that moved east from 
North Dakota's Bakken region by rail and are then exported through New 
York state. Small amounts of Canadian crude are also starting to move 
by rail to U.S. refineries, with 2011 marking the first time in 10 
years that foreign-sourced rail shipments were reported. At nearly 
1,000 barrels per day (bbl/d), this was the highest volume of foreign 
oil-by-rail recorded since EIA started publishing these data in 1981. 
In 2012 that number set a new record of more than 11,000 bbl/d.
Gasoline price decreases while diesel fuel increases
    The U.S. average retail price of regular gasoline decreased less 
than a penny to $3.49 per gallon as of July 8, 2013, up eight cents 
from last year at this time. The Midwest price increased two cents to 
$3.41 per gallon, while prices in all other regions decreased. The 
largest decrease came in the Rocky Mountain region, where the price is 
$3.61 per gallon, down three cents from last week. The Gulf and West 
Coast prices both decreased two cents, to $3.30 and $3.88 per gallon, 
respectively. Rounding out the regions, the East Coast price is down 
one cent to $3.46 per gallon.
    The national average diesel fuel price increased one cent to $3.83 
per gallon, 15 cents higher than last year at this time. The Rocky 
Mountain price decreased one cent to $3.81 per gallon, while prices in 
all other regions increased. The largest increase came on the Gulf 
Coast, where the price is up two cents to $3.75 per gallon. The East 
Coast, Midwest, and West Coast prices all increased a penny, to $3.83, 
$3.82, and $3.95 per gallon, respectively.
Propane inventories gain
    Total U.S. inventories of propane increased 1.0 million barrels 
from last week to end at 57.4 million barrels, but are 5.8 million 
barrels (9.2 percent) lower than the same period a year ago. The Gulf 
Coast region led the gain with 1.0 million barrels, while East Coast 
stocks increased by 0.2 million barrels. Midwest stocks increased by 
0.1 million barrels and Rocky Mountain/West Coast stocks decreased by 
0.3 million barrels. Propylene non-fuel-use inventories represented 5.3 
percent of total propane inventories.
                     ATTACHMENT 2--TODAY IN ENERGY
rail delivery of u.s. oil and petroleum products continues to increase, 
                             but pace slows
    With U.S. crude oil production at the highest level in two decades, 
outstripping pipeline capacity, the United States is relying more on 
railroads to move its new crude oil to refineries and storage centers. 
The amount of crude oil and refined petroleum products transported by 
rail totaled close to 356,000 carloads during the first half of 2013, 
up 48 percent from the same period in 2012, according to Association of 
American Railroads (AAR).
    U.S. weekly carloadings of crude oil and petroleum products 
averaged nearly 13,700 rail tankers during the January-June 2013 
period. With one rail carload holding about 700 barrels, the amount of 
crude oil and petroleum products shipped by rail was equal to 1.37 
million barrels per day during the first half of 2013, up from 927,000 
barrels per day during the first six months of last year. AAR data do 
not differentiate between crude oil and petroleum products, but it is 
generally believed that most of the volume being moved in the 2006-10 
period was petroleum products and most of the increase since then has 
been crude oil. Crude oil accounts for about half of those 2013 daily 
volumes, according to AAR.
    The roughly 700,000 barrels per day of crude oil, which includes 
both imported and domestic crude oil, moved by rail compares with the 
7.2 million barrels of crude oil the United States produces daily, 
based on the latest 2013 monthly output numbers from the U.S. Energy 
Information Administration.
    The jump in crude oil production from North Dakota, where there is 
not enough pipeline capacity to move supplies, accounts for a large 
share of the increased deliveries of oil by rail. North Dakota is the 
second largest oil producing state after Texas, as advanced drilling 
technology has unlocked millions of barrels of tight oil in the Bakken 
Shale formation.
    More Bakken crude oil moving to market by rail has helped narrow 
the difference between the spot prices for Bakken crude oil and 
international benchmark Brent crude oil in recent months to its 
smallest gap-less than $5 per barrel-in more than one-and- half years. 
The narrower spread reduces the incentive to ship oil to coastal 
refineries. This development, along with the lack of railcars (some 
estimates cite a 60,000 car backlog) may explain the slower growth 
shown in 2013 carload data.

    The Chairman. Very good. Thank you.
    Mr. Hume.

 STATEMENT OF JEFFREY B. HUME, VICE CHAIRMAN, STRATEGIC GROWTH 
   INITIATIVES, CONTINENTAL RESOURCES INC., OKLAHOMA CITY, OK

    Mr. Hume. Chairman Wyden, Ranking Member Murkowski and 
members of the committee, my name is Jeff Hume. I serve as Vice 
Chairman of Strategic Growth Initiatives for Continental 
Resources, an Oklahoma City-based independent oil and gas 
producer, where I've worked for the past 30 years. It's an 
honor to address you on this important subject matter at hand.
    Just to clear one thing up before we get started, I noticed 
in the purpose statement for this oversight meeting that the 
word ``boom'' is used to described the current growth in U.S. 
domestic oil production. Indeed, total petroleum liquids 
production in our country has accelerated tremendously in the 
recent years. In fact, the U.S. has recently surpassed Russia 
and is running neck and neck with Saudi Arabia in the rankings 
of the world's largest producer of petroleum liquids. However, 
oftentimes, I hear the word ``boom,'' it is used in reference 
to an air-like dot-com bubble or some other wild business cycle 
that inevitably ends in a bust. This is not the case with 
respect to the recent gains in U.S. oil production.
    A much more accurate way to describe the current rise in 
domestic production would be to use the word ``renaissance'' as 
this remarkable rebirth of the U.S. onshore oil industry is 
being driven by sustainable technology developments such as 
horizontal drilling.
    Today, crude oil is indisputably a global commodity. Our 
Nation and the world have changed remarkably since the U.S. 
crude oil export restrictions were acted in the 1970s. The 
conditions that originally justified the establishment of short 
supply controls in the wake of the 1973 Arab oil embargo are no 
longer indicative of how our petroleum supply and distribution 
channels function.
    As an American, I'm proud to say the U.S. has some of the 
most sophisticated and complex refineries in the world. 
Billions of dollars of investment have enabled our domestic 
industry to efficiently convert lower-priced heavy sour crude 
oil and bitumen imports into low sulfur fuels. But as Chairman 
Wyden noted in his March 13th letter to the EIA and again 
today, efficiency gains and growth in aggregate U.S. refining 
capacity have been accompanied by a nearly 25 percent reduction 
in the number of refineries in operation over the past decade. 
This has resulted in a greater marginal impact of a single 
domestic refinery on the supply of gasoline. Planned 
maintenance turnarounds, as well as unplanned weather-related 
events, are now more impactful than ever.
    In today's environment, 2 good ways to lower prices 
Americans pay for gasoline and fuels are to support additional 
domestic production at both private and government lands, and 
to find creative ways to make supply and distribution change 
more efficient. Supporting a strong domestic oil production 
industry is critical for the health of our economy, as it 
creates jobs and produces a valuable product for consumption or 
export.
    It is this growth in productivity and production activity 
over the past several years that has contributed to a drop in 
U.S. reliance on imported oil. It has also added high-paying 
jobs and spurred production in the Nation's large petrochemical 
industry.
    It is worth noting, however, that the energy business is 
very capital-intensive. Without current law regarding 
intangible drilling costs, otherwise known as IDCs, and 
percentage depletion, producers would not be able to generate 
the capital necessary for the continued growth in domestic 
drilling and production activity.
    A recent study by Wood Mackenzie suggests that repealing 
producer's deduction for IDCs in 2014 could result in a 15-20 
percent drop in annual domestic drilling, meanwhile, curtailing 
over 400 billions of investment from 2014-2023. Consequently, 
65,000 jobs per year would be lost in the oil and gas industry. 
To me, these figures provide powerful evidence for the need to 
maintain support of the oil and gas industry as a very positive 
contributor to our economy and American way of life.
    I'd also like to mention briefly the role of traditional 
trade restrictions on our business. In today's global economy, 
it no longer makes sense for our country to cling to the 
regulatory relics of bygone eras that restrict the export of 
domestic crude oil. The U.S. Government does not restrict the 
export of gasoline or refined fuels or other domestic energy 
sources such as coal. In fact, 2011 marked the first time in 
over 60 years that the U.S. was a net exporter of fuels. Hard-
working Americans and businesses would be much better served if 
our government would take steps to remove existing barriers 
that distort domestic oil markets and provide disincentives for 
incremental domestic production.
    Since much of the domestic light-type crude oil grades like 
the Bakken that are contributing to the U.S. energy renaissance 
are very high quality, they're actually processed most 
efficiently at less complex refineries that are specifically 
designed to handle these low sulfur grades. Following the 
restructuring of the U.S. refining industry, many less complex 
refineries best suited to efficiently process our domestic 
high-grade crude are located overseas.
    Matching the various grades of crude oil, the refineries 
best able to process them maximizes the available supply of 
refined products. By exporting our high-quality domestic crude 
to the overseas refiners whom value it most, refiners from Free 
Trade Partner countries like Japan and Korea that have 
struggled to source crude oil in the wake of Iranian sanctions, 
we can reduce our trade deficit, while also increasing the fuel 
supplies the American consumer requires. To reduce costs at the 
pump and on the monthly heating and cooling bills, it makes 
economic sense to let the marketplace, not the Federal 
Government, determine where these barrels should be processed.
    In conclusion, I would like to reiterate that maintaining 
your support for the industry and opening borders for crude oil 
will: 1) lower energy costs to American consumers and 
businesses; 2) promote job growth in the domestic energy 
sector; 3) improve our Nation's balance of trade; 4) raise tax 
revenue through GDP growth; and 5) improve national security 
and global influence.
    Last, I would like to sincerely thank you again for giving 
me the opportunity to share with you today the perspective of 
the U.S. independent producer. I look forward to addressing any 
questions you may have. Thank you.
    [The prepared statement of Mr. Hume follows:]

Prepared Statement of Jeffrey B. Hume, Vice Chairman, Strategic Growth 
       Initiatives, Continental Resources Inc., Oklahoma City, OK
    Chairman Wyden, Ranking Member Murkowski and Members of the 
Committee, my name is Jeff Hume. I serve as Vice Chairman of Strategic 
Growth Initiatives for Continental Resources, an Oklahoma City-based 
independent oil and gas producer where I have worked for the past 30 
years. It's an honor to address you on the important subject matter at 
hand. Hopefully my testimony today will provide more insight on the 
chapters our company and other independent producers are writing in 
this amazing domestic energy turnaround story.
    Just to clear one thing up before we get started, I noticed in the 
purpose statement for this oversight meeting that the word ``boom'' is 
used to describe the current growth in U.S. domestic oil production. 
Indeed, total petroleum liquids production in our country has 
accelerated tremendously in recent years. In fact, the U.S. has 
recently surpassed Russia and is running neck to neck with Saudi Arabia 
in the rankings as the world's largest producer of petroleum 
liquids.\1\ However, often times when I hear the word ``boom,'' it's 
used in reference to an era like the dot-com bubble or some other wild 
business cycle that inevitably ended in a ``bust.'' This just is not 
the case with respect to the recent gains in U.S. oil production.
---------------------------------------------------------------------------
    \1\ Source: EIA International Energy Statistics. Production of 
Crude Oil, NGPL, and Other Liquids in 2012. http://www.eia.gov/cfapps/
ipdbproject/
iedindex3.cfm?tid=5&pid=55&aid=1&cid=regions&syid=2012&eyid=2012&unit=TB
PD. Accessed July 11, 2013.
---------------------------------------------------------------------------
    A much more accurate way to describe the current rise in domestic 
production would be to use the word ``renaissance,'' as this remarkable 
``re-birth'' of the U.S. onshore oil industry is being driven by 
sustainable technological developments such as horizontal drilling. 
These revolutionary advancements have enabled companies like 
Continental Resources to unlock vast resource plays located deep 
underground, and produce oil from formations that were previously 
inaccessible using traditional methods. And, the best news of all is 
that this 21st century ``renaissance'' is moving us closer to the goal 
of North American energy independence. When we reach this goal--and are 
no longer an energy ``debtor'' nation--we will have bolstered national 
security, fortified our leadership position at the global negotiating 
table, and provided Americans with much-needed relief in the form of 
high-paying job opportunities and savings at the pump.
The Company
    Our Company was established as a small business in 1967 by Harold 
Hamm, with assets consisting of a single pump-truck and one employee in 
search of the American dream. From these humble beginnings, Continental 
Resources has grown to become the largest producer and leaseholder in 
the massive Bakken oil play in North Dakota/Montana and one of the Top 
10 producers of petroleum liquids in the United States. In addition to 
the Bakken, Continental has operations in several other states 
including Oklahoma, South Dakota and Colorado.
    The same entrepreneurial spirit and ``can do'' attitude on which 
Continental Resources was founded remains ingrained in our company 
culture. Today, our well-site teams can literally drill two miles 
straight down, shift to horizontal mode, drill another two to three 
miles sideways, and hit a target the size of a loaf of bread. Yes, 
these truly are exciting times in the energy business. Each day at 
Continental, we witness the assumptions underlying ``peak oil'' 
theories crumble under the power of creative minds and pioneering 
technology.
    At Continental, this same ingenuity is being used to improve 
workplace safety and reduce the environmental impact of our activities. 
We pioneered the use of ECO-Padsr, a design in which multiple 
horizontal wells are completed from a single drilling pad to work 
around sensitive areas and reduce our surface footprint. This type of 
drilling is typically more expensive than conventional vertical 
techniques, but as a result we have fewer rig movements and our 
operations end up being much less intrusive.
    Continental Resources' success in discovering and developing light-
tight shale oil plays around the country has not only lessened our 
Nation's dependence on foreign oil, but just as importantly, it has 
helped stimulate our domestic economy by creating high-paying jobs for 
Americans and adding tax revenue at multiple levels of government. 
According to the Bureau of Labor Statistics, the unemployment rates in 
North Dakota and Oklahoma, the two states where our Company is most 
active, were the lowest and fifth lowest nationally in 2012.\2\
---------------------------------------------------------------------------
    \2\ 2012 data sourced from the Bureau of Labor Statistics' 
``Regional and State Unemployment (Annual) News Release.'' http://
www.bls.gov/news.release/srgune.htm. Accessed July 11, 2013.
---------------------------------------------------------------------------
The Current Market
    Today, crude oil is indisputably a global commodity. Our Nation and 
the world have changed remarkably since U.S. crude oil export 
restrictions were enacted in the 1970's. The conditions that originally 
justified the establishment of ``Short Supply Controls'' in the wake of 
the 1973 Arab Oil Embargo are no longer indicative of how petroleum 
supply and distribution channels function. It is now common to see 
oilfields in nearly every continent being jointly developed by 
companies from multiple countries. This broad-based international 
ownership structure greatly diminishes the likelihood of future oil 
embargos crippling our Nation and economy, as the political interests 
of the producers are diverse.
    During this same period, the refining industry has evolved 
significantly. Every oil refinery in the U.S., or the world for that 
matter, is configured differently. At inception, each facility was 
designed and constructed to efficiently process a base slate of one or 
more foreign or domestic crude oil grades, often times sourced locally 
or from affiliated fields overseas. However, over the years, as 
refinery crude supplies, product price differentials and environmental 
regulations changed, units were added or mothballed in response to 
prevailing and forecasted economic conditions. The current 
``restructuring of the U.S. refining and distribution system'' 
mentioned in this hearing's purpose statement is a good example of 
this.
    As an American, I'm proud to say the U.S. has some of the most 
sophisticated and complex refineries in the world. Billions of dollars 
of investments have enabled our domestic industry to efficiently 
convert lower-priced heavy-sour crude oil and bitumen imports into low-
sulfur fuels. But as Chairman Wyden noted in his March 2013 letter to 
the EIA, efficiency gains and growth in aggregate U.S. refining 
capacity have been accompanied by a nearly 25 percent reduction in the 
number of refineries in operation over the past decade.\3\ This has 
resulted in a greater marginal impact of a single domestic refinery on 
the supply of gasoline. Planned maintenance ``turnarounds'' as well as 
unplanned weather-related events are now more impactful than ever.
---------------------------------------------------------------------------
    \3\ Chairman Wyden letter to Adam Sieminski of the EIA dated March 
11, 2013.http://www.energy.senate.gov/public/index.cfm/2013/3/wyden-
asks-eia-for-gasoline-market-data-to-explain-recent-price-spike. 
Accessed July 11, 2013. References Antony Andrews, et al., The U.S. Oil 
Refining Industry: Background in Changing Markets and Fuel Policies, 
Congressional Research Service, December 2012.
---------------------------------------------------------------------------
Looking Ahead
    In today's environment, two good ways to lower the prices Americans 
pay for gasoline and fuels are to support additional domestic 
production on both private and government lands and to find creative 
ways to make supply and distribution chains more efficient.
    Supporting a strong domestic oil production industry is critical 
for the health of our economy, as it creates jobs and produces a 
valuable product for consumption or export. It is this growth in 
production activity over the past several years that has contributed to 
a drop in U.S. reliance on imported oil.\4\ It has also added high-
paying jobs and spurred production in the Nation's large petrochemical 
industry. Supporting this point, a report issued in October 2012 by IHS 
Global Insight\5\ found that:
---------------------------------------------------------------------------
    \4\  Bureau of Economic Analysis, ``U.S. Trade in Goods (IDS-
0182).'' Accessed July 12, 2013.
    \5\ Source: IHS. ``Unconventional Oil and Gas Production Supports 
More Than 1.7 Million U.S. Jobs Today; Will Support 3 Million by the 
End of the Decade, IHS Study Finds,'' October 23, 2012. http://
press.ihs.com/press-release/commodities-pricing-cost/unconventional-
oil-and-gas-production-supports-more-17-millio. Accessed July 12, 2013.

   Employment attributed to upstream unconventional oil and 
        natural gas activity will support more than 1.7 million jobs in 
        2012, growing to some 2.5 million jobs in 2015, 3 million jobs 
        in 2020 and 3.5 million jobs in 2035.
   In 2012, unconventional oil and natural gas activity will 
        contribute nearly $62 billion in federal, state, and local tax 
        receipts. By 2020, total government revenues will grow to just 
        over $111 billion. On a cumulative basis, unconventional oil 
        and natural gas activity will generate more than $2.5 trillion 
        in tax revenues between 2012 and 2035.

    Not only are these factors positive economically, but from a 
national security standpoint, supporting domestic oil production is 
beneficial because it enables us to control our sources and uses of 
petroleum in a moment of crisis and decreases the likelihood of being 
drawn into future regional conflicts in geopolitically unstable, 
petroleum-exporting areas.
    It's worth noting, however, that the energy business is very 
capital intensive, and these figures just mentioned are predicated upon 
the maintaining of current legislation. Without current law regarding 
intangible drilling costs (IDCs) and percentage depletion,\6\ producers 
would not be able to generate the capital necessary for the continued 
growth in domestic drilling and production activity. A recent study by 
Woods Mackenzie\7\ suggests that repealing producers' deduction for 
IDCs in 2014 could result in a 15-20 percent drop in annual domestic 
drilling, meanwhile curtailing over $400 billion of investment from 
2014 to 2023. Consequently, 65,000 jobs per year would be lost in the 
oil and gas industry. To me, those figures provide powerful evidence 
for the need to maintain support of the oil and gas industry as a very 
positive contributor to our economy and American way of life.
---------------------------------------------------------------------------
    \6\ IDCs represent typical and ordinary business expenses within 
the oil and gas industry. This provision is not a tax subsidy or 
loophole. IDCs permit a portion of the costs of drilling a well to be 
deducted fully in the year those costs are incurred, rather than being 
capitalized over several years. Percentage depletion is akin to typical 
depletion taken by other industries, except that the depletion is 
available throughout the economic life of a well because of the 
depleting nature of oil and gas
    \7\ Study by Woods Mackenzie for the American Petroleum Institute. 
``Study: 190,000 Jobs Lost in First Year if Drilling Cost Deduction Is 
Repealed.'' http://www.api.org/news-and-media/news/newsitems/2013/july-
2013/study-190000-jobs-lost-in-first-year-if-drilling-cost-deduction-
is-repealed. Accessed July 12, 2013.
---------------------------------------------------------------------------
    I'd also like to mention briefly the role of trade restrictions in 
our business. In today's global economy, it no longer makes sense for 
our country to cling to regulatory relics from bygone eras that 
restrict the export of domestic crude oil. The U.S. government does not 
restrict the export of gasoline or refined fuels or other domestic 
energy sources such as coal; in fact, 2011 marked the first time in 
over 60 years that the U.S. was a net exporter of fuels.\8\ Hard-
working Americans and businesses would be much better served if our 
government would take steps to remove the existing barriers that 
distort domestic oil markets and provide disincentives for incremental 
domestic production.
---------------------------------------------------------------------------
    \8\ Barbara Powell, ``U.S. Was Net Oil-Product Exporter for First 
Time Since 1949,'' Bloomberg article dated February 29, 2012. http://
www.bloomberg.com/news/2012-02-29/u-s-was-net-oil-product-exporter-in-
2011.html. Accessed July 12, 2013.
---------------------------------------------------------------------------
    Since much of the domestic light-tight crude oil grades like Bakken 
that are contributing to the U.S. energy ``renaissance'' are very high 
quality, they are actually processed most efficiently at less complex 
refineries that are specifically designed to handle these low-sulfur 
grades. Following the restructuring of the U.S. refining industry, many 
less-complex refineries best suited to efficiently process our 
domestic, high-grade crude are located overseas. Matching the various 
grades of crude oil with the refineries best able to process them 
maximizes the available supply of refined product. By exporting our 
high-quality domestic crude to the overseas refiners whom value it 
most--refiners in Free Trade Partner countries like Japan and South 
Korea\9\ that have struggled to source crude oil in the wake of Iranian 
sanctions--we can reduce our trade deficit while also increasing the 
fuel supplies the American consumer requires. To reduce costs at the 
pump and on the monthly heating and cooling bills, it makes economic 
sense to let the marketplace, not the Federal Government, determine 
where these barrels should be processed.
---------------------------------------------------------------------------
    \9\ In 2012, we imported 68 thousand barrels per day of refined 
product from these two countries. Source: EIA Data, ``U.S. Imports by 
Country of Origin,'' http://www.eia.gov/dnav/pet/
pet__move__impcus__a2__nus__ep00__im0__mbblpd__a.htm. Accessed July 12, 
2013.
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                               Conclusion

    In conclusion, I would like to reiterate that maintaining your 
support for the industry and opening borders for crude oil export will:

          1. Lower energy costs to American consumers and businesses.
          2. Promote job growth in the domestic energy sector.
          3. Improve our Nation's balance of trade position.
          4. Raise tax revenue through GDP growth.
          5. Improve National security and global influence.

    Lastly, I would like to sincerely thank you again for giving me the 
opportunity to share with you today the perspective of a U.S. 
independent producer. I look forward to addressing any questions you 
may have.

    The Chairman. Very good. Mr. Klesse.

STATEMENT OF WILLIAM R. KLESSE, CHAIRMAN OF THE BOARD AND CHIEF 
 EXECUTIVE OFFICER, VALERO ENERGY CORPORATION, SAN ANTONIO, TX

    Mr. Klesse. Thank you, Mr. Chairman, and Senator Murkowski.
    I am the Chairman of the Board and CEO of Valero Energy 
Corporation. We are an independent petroleum refiner with 
assets that include 13 U.S. refineries of various size and cost 
structures, with a combined throughout capacity of 
approximately 2.3 million barrels per day; we are an ethanol 
producer; we are a renewable diesel producer, and we have a 
wind farm. We have a network of pipelines, terminals, branded 
and non-branded wholesale customers. As an independent refiner, 
Valero does not explore for or produce crude oil or natural 
gas. Rather, we purchase these and related fee stocks to 
manufacture refined products such as gasoline, jet fuel, diesel 
and many others.
    Refining is a global business and refined products are 
fungible and easily transported because the marketplace is 
global. Domestic refiners compete against international 
refineries, as well as each other. Despite the drop in U.S. 
gasoline and diesel demand, and the addition of global refining 
capacity that has been added, U.S. refiners have maintained 
high utilization that allowed them to produce excess gasoline 
and diesel fuel that then can be exported. This is a benefit to 
the U.S. economy, the American worker and the consumer.
    The invisible hand of the market itself determines prices, 
with supply and demand adjusting until markets clear. Our cost 
position acts as a floor and costs vary among companies, 
individual refineries and even within a refinery. Prices are 
very visible in the commodity exchanges around the world where 
anyone can buy and sell benchmark crude oil, natural gas 
refined products. Refiners such as Valero are in a position of 
being price takers, rather than price makers. Refiners like 
Valero do not set retail prices. Most retail stores are 
operated by marketing companies or individuals that set their 
own price. The price of crude oil represents by far the largest 
component of gasoline prices. Retail gasoline prices currently 
are composed of 67 percent crude oil, 14 percent refining, 12 
percent taxes, 8 percent distribution and marketing. On an 
average of $3.61 per gallon, only 50 percent is attributable to 
refining, while $2.40 is crude oil. Even without any refining 
benefit, we would still have crude oil over $3 per gallon. We 
are in a world of $100 crude oil. We do not expect a 
significant drop this summer.
    What is keeping prices from rising higher is the increase 
in U.S. and Canadian crude oil production and, certainly, some 
uncertainty about economic growth around the world. However, 
the U.S. remains a crude oil importer. Crude prices clearly 
reflect movements in the global marketplace and prices that we 
pay must be high enough to attract those barrels to our market. 
American refineries are essential to our economy. The industry 
employs 108,000 people and many, many more in other jobs. Think 
about all the people that our industry influences and touches.
    There are other factors affecting retail prices, some which 
can be affected by government, some which cannot. Despite the 
high cost of labor and regulations in the United States, 
increased natural gas production has resulted in much lower 
prices and is allowing our industry to be competitive, 
especially in the Atlantic Basin. A very careful and balanced 
approach to LNG export policy is important for refiners. We 
also believe it's important to have crude oil come to the 
United States where the jobs are; that's why we support the 
Keystone Pipeline.
    But today, the most important thing that's affecting us is 
the Renewable Fuel Standard. Valero is the third largest corn-
ethanol producer, but the Renewable Fuel Standard is out of 
control. It is broken. RINs are going up probably as we speak; 
I'm told they're over a dollar, $1.30 here per RIN gallon. The 
RFS must be fixed. This cost is just skyrocketing. It was OK 
when the first law was passed in 2005, but when the new law, or 
the revised law in 2007, the RIN program was not revised. We 
have announced that this is going to cost Valero $750 million 
this year, and with the RIN price at the numbers we're talking 
about now, it'll be much higher. We support and believe that 
ethanol will be part of the fuel mix in this country, but the 
RFS is broken. There is no cellulosic to speak of. Any other 
advanced ethanol has to be imported. This is not in the 
interest of our country.
    Thank you very much for allowing me to speak, and we're 
very proud to be part of this panel.
    [The prepared statement of Mr. Klesse follows:]

  Prepared Statement of William R. Klesse, Chairman of the Board and 
  Chief Executive Officer, Valero Energy Corporation, San Antonio, TX
    My name is Bill Klesse, I am the Chairman of the Board and CEO of 
Valero Energy Corporation. Valero is a Fortune 500 company based in San 
Antonio, Texas. We are the world's largest independent petroleum 
refiner, with assets that include 13 U.S. refineries with a combined 
throughput capacity of approximately 2.3 million barrels per day, 
ethanol, renewable and wind energy facilities, a network of pipelines, 
terminals and branded and unbranded independent wholesale customers.
The Current Environment for Refining In the U.S.
    As an independent refiner, we do not explore for or produce crude 
oil or natural gas. Rather, we purchase crude oil, natural gas, and 
related feedstocks as inputs in a sophisticated manufacturing process 
to produce familiar refined products such as gasoline, jet and diesel 
fuel, and other petroleum products. Prices of these products are a 
result of a complex set of factors such as international markets, input 
prices, labor, transportation, and other costs. Independent refiners 
such as Valero cannot determine consumer prices. Indeed, the 
``invisible hand'' of the market itself determines prices with supply 
and demand adjusting until markets clear. It is a global market as 
products are fungible (specifications can vary) and easily transported. 
Refined products move to the highest priced areas. Over time, prices 
between markets can reflect unique specifications and locations, but 
will move to freight costs and logistics access.
    The U.S. is the largest, most sophisticated market for refined 
petroleum products in the world with New York Harbor being a pricing 
point and the U.S. Gulf Coast a huge physical supply market. The modern 
oil and gas industry has been providing energy for Americans for nearly 
150 years. During this time, the industry has proved cyclical and 
seasonal. No new refinery with significant operating capacity has been 
constructed since the 1980s, while the total number of refineries has 
decreased by half, overall capacity has increased from 16,859,000 
barrels-per-calendar-day then to 17,823,659 barrels-per-calendar-day 
with an annual utilization rate of about 89 percent today.\1\ As the 
number of U.S. re 1 fineries has declined, the operating capacity 
complexity of the remaining refineries has been increased to keep up 
with worldwide demand. Imports and exports also influence market prices 
and prices are very visible in the commodity exchanges around the world 
where anyone can buy and sell benchmark crude oil, natural gas, and 
refined products.
---------------------------------------------------------------------------
    \1\ U.S. Energy Information Administration.
---------------------------------------------------------------------------
    The refining industry was hit hard by the recent recession. Much of 
the financial news regarding U.S. refining was uniformly negative since 
the beginning of the recession in 2008 through last year. Rising crude 
oil prices, declining demand and ever-changing regulations led to weak 
margins for refiners, even causing several East Coast refineries to 
shut down.\2\ While crude prices remain high, and demand is still down 
about 10 percent today compared to pre-recession levels, the outlook 
for refiners has improved significantly due to the increase in North 
American natural gas and crude oil production which are giving the 
industry competitive advantages in the global market.
---------------------------------------------------------------------------
    \2\ Oil & Gas Journal. US Refining Outlook Rosier than it Seems. 
December 3, 2012. http://www.ogj.com/articles/ print/vol-110/issue-12/
processing/us-refining-outlook-rosier-than.html
---------------------------------------------------------------------------
    Valero in particular has sought to benefit from the revolution 
resulting from increased domestic shale gas and oil production. 
Refining is energy intensive, and Valero consumes about 700 million 
cubic feet a day of natural gas. In fact, energy is the largest 
component of a refinery's variable operation costs. Additionally, 
natural gas liquids are an important ingredient in creating finished 
products from crude oil, and the current supply dynamics have reduced 
the costs of these feedstocks. As shale oil production has increased, 
larger volumes of crude oil from highly productive basins like the 
Bakken and Eagle Ford have replaced imports for the domestic refining 
industry.
    The marketplace for crude oil, natural gas and refined products is 
global, as products can easily be produced and transported across the 
world. Domestic refiners, therefore, compete against international 
refiners as well as each other. Despite the drop in domestic demand and 
additional global refining capacity constantly being added, U.S. 
refineries have maintained high utilization rates that allow them to 
produce excess gasoline and diesel fuel that can be exported. This is a 
benefit to the U.S. economy as the jobs and value added are here in the 
U.S.
    The important point is that any policies making it more difficult 
to refine in the U.S. are contrary to the public interest. There are 
things that the industry and regulators cannot control, such as the 
prices of crude oil, feedstocks and utilities. However, there are 
things, such as regulations and taxes, which regulators can control. 
Reducing those controllable costs will help bring consumer prices down 
and improve further the competitiveness of the U.S. refining industry 
to be able to export excess refined products.
Relationship between Refining, Consumer Price and Supply
    As I noted, the process by which consumer prices for refined 
products, including gasoline, are set is very complex. The ``invisible 
hand'' of the market balances supply and demand in the way it does for 
other familiar products and commodities. The costs of production cannot 
be calculated by a simple equation and varies not only among companies 
but even within the individual process units of a single refinery. 
Ultimately, because of the wide range of variables affecting gasoline 
prices are outside of the control of a refiner, and because of the 
competitive and robust size of the U.S. market, refiners such as Valero 
are in position of being price takers rather than price makers and use 
linear program computer models to optimize a refinery.
    It has long been recognized that the price of crude oil plays a 
major role in determining the cost of refined products. Crude oil 
represents by far the largest component of gasoline prices, and it is 
important to remember that crude oil prices are completely out of 
independent refiners' control and are clearly set by the global market, 
adjusted for quality and location. Retail gasoline prices currently are 
composed of about 67 percent crude oil costs, 14 percent refining costs 
and profits, 12 percent taxes and 8 percent distribution and marketing 
costs and profits. Of a recent average retail gasoline price of $3.61 
per gallon, only 50 cents can be attributed to refining, while $2.40 
would be attributed to crude. Even if refiners could somehow make fuels 
at absolutely no cost, and did not make any profits, gasoline would 
still cost well over $3 per gallon today.
    Despite the recent rise in domestic crude oil production, oil 
prices overall have not fallen significantly. The U.S. remains a net 
crude oil importer, so crude prices clearly reflect movements in the 
global marketplace as the prices paid must be high enough to attract 
the imported crude supply to America.
    There are other factors affecting retail product prices, some of 
which can be affected by government policy. According to the Energy 
Information\3\Administration (EIA), the wide range of factors that 
combine with the price of crude to set the retail price for gasoline 
include:\4\
---------------------------------------------------------------------------
    \3\ Energy Information Administration. ``Frequently Asked 
Questions.'' http://www.eia.gov/tools/faqs/faq.cfm? id=3&t=10
    \4\ Energy Information Administration. ``Factors Affecting Gasoline 
Prices.'' http://www.eia.gov/energyexplained/ 
index.cfm?page=gasoline__factors__affecting__prices
---------------------------------------------------------------------------
Different gasoline formulations required in different parts of the 
        country
    Over the years, federal and state governments have required that 
refiners produce a range of specialized gasoline blends. Neutral third 
parties such as the Government Accountability Office (GAO) have long 
recognized that the rising number of required fuel blends results in a 
variety of additional costs for refiners that increase the retail price 
of gasoline.\5\ As the GAO has explained:
---------------------------------------------------------------------------
    \5\ GAO, Motor Fuels: Understanding the Factors That Influence the 
Retail Price of Gasoline (May 2005) http:// www.gao.gov/assets/250/
246501.pdf

          Many experts have concluded that the proliferation of these 
        special gasoline blends has caused gasoline prices to rise and/
        or become more volatile, especially in regions such as 
        California that use unique blends of gasoline, because the 
        fuels have increased the complexity and costs associated with 
        supplying gasoline to all the different markets.\6\
---------------------------------------------------------------------------
    \6\ http://www.gao.gov/assets/120/111642.pdf
---------------------------------------------------------------------------
Transportation, distribution, and marketing costs
    A major variable impacting retail gasoline prices are the costs 
associated with transportation and distribution of crude oil and 
gasoline. The product supply infrastructure involves virtually all 
aspects of transportation infrastructure, touching on pipelines, 
barges, ships, terminals, rail, trucking, and storage tanks.\7\ 
Permitting and siting delays connected to the construction of new 
pipelines and other infrastructure can drive up retail prices and make 
gasoline prices more volatile because of inevitable supply disruptions 
related to equipment problems, weather events, or other unpredictable 
and uncontrollable events.\8\
---------------------------------------------------------------------------
    \7\ GAO, Increasing Globalization of Petroleum Products Markets, 
Tightening Refining Demand and Supply Balance, and Other Trends Have 
Implications for U.S. Energy Supply, Prices, and Price Volatility, at 2 
(Dec. 20, 2007) http:// www.gao.gov/assets/280/270682.pdf
    \8\ Id. at 9-10.
---------------------------------------------------------------------------
The specific location of individual retail outlets
    Gasoline prices are highly variable based upon specific location. 
As the GAO has explained, ``Retail gasoline prices can vary from one 
region of the United States to another, between and within states and 
cities, and even within neighborhoods.''\9\ Proximity to refineries, 
regulation by all levels of government, and competition in local 
markets all combine to have significant impacts on retail prices in 
ways that cannot be controlled by refiners. Most retail outlets are 
operated by independent business people. They set their retail price.
---------------------------------------------------------------------------
    \9\ GAO. Motor Fuels: Understanding the Factors That Influence the 
Retail Price of Gasoline. May 2005 at 36 http:// www.gao.gov/assets/
250/246501.pdf
---------------------------------------------------------------------------
Taxes
    One of the most important variables related to retail gasoline 
prices are taxes imposed by federal, state and in some cases, local 
governments. The GAO has reported that ``differences in gasoline taxes 
help explain why gasoline prices vary from place to place in the United 
States.''\10\
---------------------------------------------------------------------------
    \10\ Id. at 5, 42.
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The market for non-gasoline products
    Refineries cannot produce only gasoline and diesel. The refining 
process results in a significant portion of each barrel of crude oil 
becoming products other than transportation fuels.\11\ The actual yield 
of refined products depends on refinery processes and type of crude 
processed. The production and marketing of these products, which 
typically sell at a gross margin loss compared with the price of crude 
oil, has to be offset by the sales of profitable products. While low-
cost natural gas has benefited refiners operating and feedstock cost, 
it has also resulted in lower margins on natural gas liquids and 
petrochemical feedstocks that the refinery produces. However, the net 
benefit is positive.
---------------------------------------------------------------------------
    \11\ Id. at 1.
---------------------------------------------------------------------------
Importance of the U.S. Refining Industry: Economic Benefits
    America's refineries are an essential part of the U.S. economy. 
According to a 2012 report by the American Petroleum Industry (API), 
the refining sector directly employs approximately 108,000 American 
workers throughout the country and also employs four times that many 
workers in support industries. These are high-paying jobs (average 
annual income of $94,500), filled by highly skilled American workers 
across the country. New, large scale refineries, with a typical 
refining capacity of approximately 450,000 barrels per day, employ an 
average of 1,500 refinery workers and 1,400 contracted employees.\12\ 
Valero and its subsidiaries directly employ approximately 8,300 
employees in the U.S.
---------------------------------------------------------------------------
    \12\ American Petroleum Industry. Fact Sheet: Importance of a 
Strong Refining Industry. February 24, 2012. http:// www.api.org//
media/Files/Oil-and-Natural-Gas/Refining/Domestic-Refining-Study-Facts-
Key-Points.pdf
---------------------------------------------------------------------------
    The refining sector literally fuels America's economy. Refiners 
manufacture gasoline, diesel fuel, home heating oil, jet fuel, and 
other refined products and petrochemicals--vital inputs to almost every 
sector of the economy. Most people know refineries make fuels, but the 
refineries also provide Americans with essential products created from 
petrochemicals used in business and everyday life, such as plastics and 
polymers used in computers, medical equipment, wind turbines, solar 
panels, cosmetics and so much more. Refining is necessary to process 
and upgrade crude oil. Without refineries to process crude oil, we 
would be left without the basic building blocks of our national 
economy. Additionally, by doing this manufacturing domestically, 
billions of dollars flow into the U.S. economy, supporting many other 
American jobs and families.
    The U.S. refining industry affects employment in a number of 
different ways. The obvious example is in the creation of construction 
jobs for workers and jobs at the refinery as refineries are upgraded 
and maintained. However, hundreds of jobs are also created during the 
equipment manufacturing and fabrication process. Refineries are often 
the major source of employment in cities throughout the nation, 
providing jobs for engineers, equipment specialists, operators, 
laboratory technicians, maintenance personnel, security officers and, 
administration, computer and other staff positions\13\ The oil and 
natural gas industry contributed substantially to the nation's recovery 
from the recent economic downturn, accounting for 3 percent of net job 
creation since 2009.\14\
---------------------------------------------------------------------------
    \13\ Wood Mackenzie, 2011.
    \14\ American Petroleum Industry. American Made Energy-Report to 
the Platform Committee. 2012. http:// www.api.org/policy-and-issues/
policy-items/american-energy//media/Files/Policy/American-Energy/
American- Made-Energy__HiRes.ashx
---------------------------------------------------------------------------
    The refining industry also directly and indirectly contributes 
greatly to the U.S. GDP, and provides tax revenue. The income, sales, 
use, and property taxes paid by the industry provide much revenue to 
federal, state, and local governments. At state and local levels, much 
of this tax revenue directly benefits citizens because this money is 
often used for funding schools and building roads. Refineries also help 
the U.S. economy through their continual capital expenditures, wages, 
interest and dividend payments, charitable contributions and local 
support. Without a strong domestic refining industry, the U.S. would 
risk significant direct and indirect job loss, threatened economic 
security, and weakened global competitiveness. Valero has invested in 
its refineries and its people, significantly. Valero's capital spending 
has been one of the highest, if not the highest, in the U.S. refining 
industry.
    The U.S. refining industry also has the ability to export products 
overseas, which in effect elevates the nation's status as a strong 
competitor in the global economy. The U.S. has gone from a net importer 
of petroleum products (including finished petroleum products and 
gasoline blending components) in 2005, to a net exporter in 2012.\15\ 
The ability to export refined products has kept marginal refineries 
open, ultimately benefiting consumers, our economy, workers and 
communities while enhancing our balance of trade.
---------------------------------------------------------------------------
    \15\ American Fuel & Petrochemical Manufacturers. Annual Report. 
2013. http://www.afpm.org/uploadedFiles/ Content/About__AFPM/
AFPM__2013__Annual__Report.pdf
---------------------------------------------------------------------------
Importance of the U.S. Refining Industry: Energy Independence and 
        National Security
    While Valero's locations and technology have put it in an ideal 
position to benefit from the increased North American oil and natural 
gas production, Valero is also an active participant in international 
crude markets--enabling it to benefit from a balanced and pragmatic 
portfolio of inputs. In this same spirit, we recognize the importance 
of the oil sands developments under way within the borders of our close 
ally Canada. Valero supports construction of the Keystone XL Pipeline 
and believes it will be in the strong energy security and economic 
interest of the U.S. and will bring a specific quality of crude suited 
for many U.S. Gulf Coast refineries to the Gulf Coast market.
Energy Efficiency and Environmental Improvements
    Since 1990, the refining industry as a whole has spent over $128 
billion on environmental improvements.\16\ Though the industry has 
greatly expanded during this time, environmental emissions have 
decreased over the last 20 years. This decrease in emissions comes 
despite increasingly stringent refined product specifications, and an 
overall increase in refinery production of gasoline and jet and diesel 
fuels. Processing heavier and sour crude that have been available to 
the market has required more processing.\17\
---------------------------------------------------------------------------
    \16\ Wood Mackenzie, 2011.
    \17\ Thomas P. Nelson, ``An Examination of Historical Air Pollutant 
Emissions from US Petroleum Refineries,'' November 29, 2012. http://
onlinelibrary.wiley.com/doi/10.1002/ep.11713/pdf
---------------------------------------------------------------------------
    Petroleum refining is an energy intensive industrial process, but 
the industry has made record improvements to lessen its environmental 
footprint. Environmental stewardship is a core value at Valero. As an 
example, we have spent approximately $525 million to build a state-
ofthe- art flue-gas scrubber, one of the world's largest, at our 
Benicia refinery in California. This expenditure reduced sulfur dioxide 
emissions by 95 percent and nitrogen oxide emissions by 55 percent.\18\ 
Valero has also spent $2.6 billion at its refineries on environmental 
upgrades that further reduced emissions during the last six years. 
Under a comprehensive Energy Stewardship Program, Valero refineries 
reduced energy consumption per barrel of throughput by 12 percent 
between 2008 and 2012 which has reduced our green house gas emissions.
---------------------------------------------------------------------------
    \18\ Donna Beth Weilenman. Refinery to test new scrubber. The 
Benicia Herald. December 4, 2010. http:// beniciaherald.me/2010/12/04/
refinery-to-test-new-scrubber/
---------------------------------------------------------------------------
    The refining industry is constantly adapting to changing times and 
is leading the way in the development of renewable fuels, and Valero is 
playing an active role in this innovation. Valero acquired 10 state-of-
the-art ethanol plants, which operate under our subsidiary Valero 
Renewable Fuels Company, LLC, making Valero the first traditional 
refiner to enter the ethanol production market in a significant way. 
Also, Diamond Alternative Energy LLC, a Valero subsidiary, produces 
renewable diesel fuel from recycled animal fat and used cooking oil in 
partnership with Darling International Inc. at a 10,000-barrel-per-day 
unit at the St. Charles Refinery in Louisiana that just became 
operational.\19\
---------------------------------------------------------------------------
    \19\ Nicolas Zeman. Valero's Renewable Diesel Plant Nears Start-Up. 
ENR Louisiana & Texas. April 22, 2013. http:// texas.construction.com/
texas--construction--projects/2013/0422-valero8217s-renewable-diesel-
plant-nears-startup. asp
---------------------------------------------------------------------------
    Valero's environmental efforts have consistently been recognized. 
In 2013 Valero's McKee Refinery received the Texas Environmental 
Excellence Award for the company's wind farm that reduces reliance on 
conventional power sources.\20\ Additionally, Valero's St. Charles 
Refinery was recognized by the Louisiana Department of Environmental 
Quality and the Louisiana Chapter of the Air and Waste Management 
Association for its catalytic cracker conversion project that reduced 
overall facility air emissions and eliminated thousands of tons of 
waste catalyst generated annually.\21\
---------------------------------------------------------------------------
    \20\ Texas Commission on Environmental Quality. Texas Environmental 
Excellence Awards 2013. May 2013. http:// www.tceq.texas.gov/
publications/pd/020/2013-NaturalOutlook/texas-environmental-excellence-
awards-2013
    \21\ St. Charles Herald Guide. Valero spends $600 million on 
environment. May 7, 2008. http:// www.heraldguide.com/
details.php?id=4017
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The Unique Dynamic of Renewable Fuels
    One of the most challenging factors facing the fuels market place 
is the implementation of the federal Renewable Fuels Standard (RFS). As 
a company, Valero has met the challenge of the RFS by becoming a market 
leader in the production of alternative transportation fuels. We are 
currently the third largest corn ethanol producer in the U.S. and have 
recently begun the production of renewable diesel fuel, as mentioned.
    Whether or not one supports alternative fuel production, 
policymakers are right to be concerned with the impacts on consumer 
gasoline prices caused by the way in which the RFS is currently 
implemented. As the Committee is well aware, obligated parties under 
the RFS, refiners and importers, but not blenders, are required to 
demonstrate compliance with their renewable volume obligation (RVO) 
through the submission of renewable identification numbers (RINs). 
Unfortunately, the RINs market has caused significant unintended 
consequences. With the original 2005 law and its volumes, RINs were 
necessary for flexibility and the ability to track the program. When 
the law was revised in 2007 and the renewable volumes greatly 
increased, combined now with much lower than expected gasoline demand, 
RINs have become a huge cost and fairness issue. Also, in the past two 
years, the RINs market has been beset by allegations of fraud that has 
questioned the Environmental Protection Agency's (EPA) ability to 
administer the RFS program and resulted in increased compliance costs 
for obligated parties-most of which are passed on to consumers.
    Most importantly, as U.S. gasoline demand declined from 2007 and as 
the renewable fuels mandate volumes increase, some U.S. refiners--those 
that are large merchants and wholesale, spot sellers--find themselves 
in an unintended predicament of either reducing gasoline production, 
exporting more gasoline at discounted prices, or buying renewable fuel 
credits (RINs), which soon may not even be available because the market 
is going infeasible. If the option of buying RINs doesn't exist because 
none are available or because of very high pricing, the domestic supply 
will be reduced. It's hard to believe that when Congress passed the 
Energy Independence and Security Act of 2007, a possible outcome was to 
reduce U.S. gasoline supplies and increase gasoline prices. However, as 
a refiner and an ethanol producer, that is exactly the potential 
outcome we find ourselves in today. No one expects that U.S. gasoline 
demand will rebound strongly and to begin to grow again, and there are 
physical constraints on using higher blends of ethanol in gasoline 
including the lack of car warranties to approve those blends. As a 
result, there simply aren't enough gallons of gasoline in which to put 
all of the required gallons of ethanol--and that has driven the price 
of corn ethanol RINs from $0.05 in late 2012 to as high as $1.16 
recently.\22\ Also, there is no cellulosic ethanol and advanced ethanol 
has to be imported.
---------------------------------------------------------------------------
    \22\ See Mario Parker. Gasoline Price Inflated by Ethanol in Oil 
Boom: Energy Markets. Bloomberg. March 21, 2013. http://
www.bloomberg.com/news/2013-03-21/gasoline-price-inflated-by-ethanol-
in-oil-boom-energymarkets.html
---------------------------------------------------------------------------
    At Valero alone, we anticipate cost increases of some $500 to $750 
million this year just as a result of volatility in the market for 
RINs. Unfortunately, this cost will not add one more gallon of fuel 
into the market. It is nothing more than a federally mandated cost to 
each gallon of transportation fuel that may be passed on to the 
consumer.\23\ At the outset of the RFS, EPA found in its regulatory 
preamble that RIN's cost would be negligible. This estimate has turned 
out to be profoundly incorrect as the program approaches an infeasible 
situation, expected in 2014.
---------------------------------------------------------------------------
    \23\ See Bradley Olson. Drivers risk $13B gas-price hike as ethanol 
charge grows. Bloomberg. March 19, 2013. http:// fuelfix.com/blog/2013/
03/19/drivers-risk-13-billion-gas-price-hike-as-ethanol-charge-grows/
---------------------------------------------------------------------------
    Some have suggested, including the EPA, that the refining sector 
should move the percentage of ethanol blended from 10 percent to as 
high as 15 percent, a blend called E-15. While Valero supports ethanol 
and is a leading producer, experts have repeatedly noted that the E-15 
blend is not warranted for use by 95 percent of cars on the road today. 
E-15 reduces engine life and prompts fuel pump failures and consumer 
misfuelings. American Automobile Association (AAA) even called on EPA 
``to suspend the sale of E-15 until motorists are better 
protected.''\24\ There are also issues with boats, lawn mowers, 
motorcycles and other small engines. Greater reliance on higher ethanol 
blends is not the way to go, and would likely undermine consumer 
confidence in alternative fuels. Plus, we must all consider the effect 
corn ethanol in fuel has had on world food prices.
---------------------------------------------------------------------------
    \24\ See AAA CEO Urges Suspension of E15 Gasoline Sales in 
Testimony to Congress, AAA Public Relations. February 26, 2013. http://
newsroom.aaa.com/2013/02/aaa-ceo-urges-suspension-of-e15-gasoline-
sales-in-testimonyto- congress/
---------------------------------------------------------------------------
    There is also the issue of refiners and importers--but not 
blenders--being obligated parties under the RFS. Thus, a very unlevel 
market has been created with winners and losers being picked within the 
same market place--in other words, who is getting the RIN value. 
Basically, it is a zero sum business in corn ethanol RINs.
    No matter what one's view on ethanol and other alternative fuels 
is, it is time to revisit the current implementation of the RFS in 
order to allow the orderly movement of renewable fuels into the fuel 
supply in a responsible manner that protects consumers and small 
businesses. The oil supply picture has changed, the basis of the 
original legislation has changed, the RFS should be repealed and new 
legislation developed.
Implications of Outages
    Some observers, particularly in the West, have questioned the role 
of refinery outages in consumer prices. For environmental and safety 
reasons, it is necessary every few years to shut down an operating unit 
for a ``turnaround.''\25\ Generally, turnarounds are scheduled for 
lowdemand seasons with weather considered for efficient turnaround 
execution. Supply arrangements are made to cover for lost production, 
and there is currently surplus refining capacity in the United States. 
But unforeseen problems can complicate even the best plans, resulting 
in localized supply concerns. Clearly, as refineries have become 
larger, unplanned outages because of mechanical problems have caused 
increased priced volatility seen by the consumer.
---------------------------------------------------------------------------
    \25\ Managing Plant Turnarounds and Outages. CED Engineering, at 1-
2
---------------------------------------------------------------------------
    The Federal Trade Commission has monitored the petroleum industry 
for years, including during the aftermath of Hurricane Katrina, for 
possible collusion and market manipulation. They found:

          no evidence to suggest that refiners manipulated prices 
        through any of these means. Instead, the evidence indicated 
        that refiners responded to market prices by trying to produce 
        as much higher-valued products as possible, taking into account 
        crude oil costs and physical characteristics. The evidence also 
        indicated that refiners did not reject profitable capacity 
        expansion opportunities in order to raise prices.\26\
---------------------------------------------------------------------------
    \26\ William e. Vocacic, FTC Commissioner, p. 15

    The bottom line is that refiners take measures to limit the effect 
of unit outages on inventory and supply. These include increased 
production of alternate units, continued production from partially shut 
down units, import of alternate supply, and stockpiling of inventory 
leading up to a turnaround or outage. These steps are crucial to 
avoiding a major disruption in supply from a single outage. When there 
are regional shortages caused by hurricanes or other factors affecting 
refinery production, one area where regulators can help is by quickly 
providing Jones Act waivers that would increase the number of available 
ships, so that fuel supplies can quickly be moved from unaffected parts 
of the country.
Addressing Obstacles with Price Impacts
            Fix the RFS
    Within the context of the current RFS, it is clear that we must fix 
its implementation through the RINs market. Though not directly under 
this committee's mandate, RINs pricing is affecting gasoline prices. I 
applaud this Committee's attention to this issue and urge Congress to 
take action. As explained above, circumstances in the RINs market have 
changed dramatically since the mechanism was first established. Due to 
reduced gasoline demand, the ethanol blend wall, instances of RIN 
fraud, and other factors, there are not enough gallons of gasoline to 
blend with ethanol when marketing E-10 and E-85. This has led to higher 
prices and substantial uncertainty in the gasoline market. The RFS 
needs to be completely redone.
    Valero has long worked cooperatively with state and federal 
regulators on implementation issues associated with the RFS. But now it 
is time to re-examine the RFS. What is the purpose of the RFS now? 
Remember there is no cellulosic ethanol available and what might come 
to market is very limited and totally uneconomic.
Develop a Reasonable Energy Exports Posture
    A reasonable natural gas exports policy can maximize energy 
security and can protect consumer interests. But unfettered exports of 
natural gas and maybe someday, crude oil--raw materials to which 
American workers and American manufacturing can add significant value--
may have significant unintended consequences and will raise costs.
    Similarly, policies that increase U.S. refining costs may make us 
less competitive for exports. Policies that are too restrictive towards 
gasoline exports could undermine or even close marginally profitable 
refineries. The U.S. refining industry is a very efficient, but as all 
manufacturing, is faced with high labor and regulatory costs. Low 
priced natural gas offsets these costs and keeps us competitive. Valero 
urges a balanced and sensible approach to natural gas exports.
Enhance Domestic Energy Production
    We live in extraordinary times for the U.S. energy sector. The 
rapid increase in production of domestic crude oil and natural gas is 
the most significant development that I have seen in my more than four 
decades in the energy business. According to the most recent figures 
from the EIA, oil from shale now accounts for 30 percent of total U.S. 
production and natural gas from shale is now responsible for 40 percent 
of total production.\27\ We have turned the clock back 20 years 
considering imports and production of oil and for natural gas, 
production is higher than it has ever been.
---------------------------------------------------------------------------
    \27\ See Shale-Gas Estimate Rises, Tennille Tracy, Wall St. Journal 
(Jun. 10, 2013) available at: http://online.wsj.com/ article/
SB10001424127887324634304578537801148740028.html
---------------------------------------------------------------------------
    Like many major domestic manufacturing industries, the refining 
sector is energy intensive. In addition to lower operating costs from 
lower-priced natural gas, the availability of vast new supplies of 
crude oil to refineries on the U.S. coasts has made these plants more 
competitive. This increase in competitiveness and profitability in the 
refining sector ultimately benefits consumers in the form of lower 
gasoline and diesel prices. To jeopardize this development with 
burdensome one-size-fits-all federal regulations would be foolhardy and 
harmful to America's economy and American workers.
Establish a Predictable Regulatory Framework
    Refinery operations are subject to extensive environmental 
regulations. Refiners are among the most regulated industry in the 
country, and U.S. refineries are already among the cleanest and most 
efficient in the world. A reasonable approach to regulation is one that 
both improves the environment while allowing the industry to remain 
competitive. A host of recent actions by EPA, referred to as the 
``regulatory swamp'' due to the close proximity of their compliance 
targets and high costs, with very limited benefits, will create a 
highly unpredictable regulatory environment for our industry. These 
include:

   Proposed Tier 3 Gasoline and Diesel Standards--
   Greenhouse Gas Rules and Permitting
   Finalized National Ambient Air Quality Standards (NAAQS) for 
        Particulate Matter
   Finalized Mercury Air Toxics Rule--Finalized Emission 
        Standards for Boilers
   Final New Source Performance Standards (NSPS) for Oil and 
        Gas Production
   Finalized Greenhouse Gas Standards for Cars and Light Trucks
   Final National Emissions Standards for Hazardous Air 
        Pollutants at Petroleum Refineries
   Proposed Uniform Standards for Storage Vessels, Transfer 
        Operations, Equipment Leaks, Closed Vent Systems, Control 
        Devices
   Pending reconsideration to the NAAQS for NO2, SO2, and Ozone
   Pending NSPS and emission guidelines for refineries

    Valero has estimated that its costs alone for compliance with the 
Proposed Tier 3 standards will be between $300 million and $400 million 
and will raise the cost of manufacturing gasoline a couple of cents per 
gallon. It will also increase our green house gas emissions because of 
the additional processing. That said, we support clean burning fuels.
    In addition to EPA, other regulatory agencies and states have 
pursued independent regulations. For example, California's Low Carbon 
Fuel Standard (LCFS) and statewide capand- trade program were issued as 
part of the state's Global Warming Solutions Act. The LCFS in 
particular does little to achieve environmental objectives while 
discriminating against crude sources to the detriment of California 
consumers. These rules pick winners and losers among the refining 
industry in place of letting market forces operate as impacts reflect 
the individual refinery configurations and your access to specific 
crude oils.
    Environmental laws and regulations are becoming more stringent and 
new environmental laws and regulations are continuously being enacted 
or proposed. The impact of these rules on the sector is real. One 
report noted:

          As these regulations increase capital expenditures, and 
        subsequently raise costs of operations they continue to 
        pressure the economic sustainability of refinery operations, 
        which under the current low margin environment can increase the 
        risk of refinery closures and consequential job and economic 
        loss. Overall, the regulations tend to create unintended 
        consequences that duly disadvantage the US domestic refining 
        industry relative to other refining centers of the world. The 
        risks of this imply that companies could thus move operations 
        to other countries with less stringent controls, increasing 
        domestic manufacturing shutdowns, with implicit employment and 
        tax revenue loss as opportunities are created overseas.\28\
---------------------------------------------------------------------------
    \28\ Wood Mackenzie, 2011.

    This is not just a hypothetical. A 2011 report by the Department of 
Energy found that the cumulative burden of federal regulations was a 
significant factor in the closure of 66 domestic petroleum refineries 
from 1990 to 2010.\29\ In addition to increasing the cost of gasoline, 
additional regulations ``may lead to additional job losses for America, 
weaken the U.S. economy, make America more reliant on nations in 
unstable parts of the world for vital fuels and petrochemicals, and 
ultimately endanger our national security.''\30\
---------------------------------------------------------------------------
    \29\ U.S. Department of Energy. March 2011. http://www.epa.gov/
otaq/fuels/renewablefuels/compliancehelp/smallrefinery-exempt-study.pdf
    \30\ Written Statement Of American Fuel & Petrochemical 
Manufacturers. United States House Of Representatives Committee On 
Homeland Security Subcommittee On Counterterrorism And Intelligence. 
``The Implications Of Refinery Closures For U.S. Homeland Security And 
Critical Infrastructure Safety.'' March 19, 2012 http:// 
homeland.house.gov/sites/homeland.house.gov/files/Testimony percent20-
percent20Drevna.pdf
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Avoid Tax Policy Changes with Unintended Consequences
    Tax reform is a timely topic that is garnering increasing attention 
from Congress. Valero is currently subject to extensive tax 
liabilities, and changes to tax law and regulations will directly 
affect our businesses. We support reforms that will promote domestic 
competitiveness, investment, and job creation. This includes lower 
effective tax rates on manufacturers, and maintaining accounting 
methods like ``last-in, first out'' and the Section 199 deduction for 
manufacturing to stimulate economic activity at home. For companies 
like Valero that have overseas operations, we need provisions in the 
tax code that allow us to repatriate foreign earned income that we want 
to reinvest or distribute to our investors, most of whom are American. 
A fair tax code for domestic refiners ensures a healthy refining 
sector, benefitting the consumers and businesses that rely upon our 
products.
    The increased crude oil and natural gas production in North America 
is creating huge opportunities for a U.S. manufacturing resurgence. On 
behalf of Valero Energy, I thank you for the opportunity to share our 
views.

    The Chairman. Thank you very much, Mr. Klesse.
    Mr. Gilligan, welcome.

   STATEMENT OF DAN GILLIGAN, PRESIDENT, PETROLEUM MARKETERS 
             ASSOCIATION OF AMERICA, ARLINGTON, VA

    Mr. Gilligan. Chairman Wyden, Senator Murkowski, 
distinguished members of the committee, thank you for the 
invitation to be here today.
    I'm Dan Gilligan. I serve as President of The Petroleum 
Marketers Association of America. PMAA is a federation of 48 
State and regional trade associations representing 8,000 
petroleum marketing companies nationwide, the majority of which 
are small businesses as defined by SBA. These companies are 
very diverse, but they all have one thing in common: they all 
bring to market liquid fuels such as gasoline, diesel, heating 
oil, ethanol, biodiesel, jet fuel and kerosene. Our member 
companies are engaged in the transport story to the sale of 
refined products on both the wholesale and retail level. They 
supply gasoline to convenience stores, diesel to truck stops, 
lubricants to industry and heating oil to millions of 
customers. Not only are these companies primary suppliers of 
fuel, they also own and operate over 80,000 retail facilities. 
They are also specialists in serving farmers, railroads, 
marinas and airports with the fuels they need.
    Petroleum marketing companies do not benefit from high 
gasoline or diesel prices. Because they operate in such a 
transparently competitive environment, higher wholesale prices 
must be absorbed by retailers until street prices catch up. In 
order to remain competitive, retailers usually offer the lowest 
price for gasoline to generate volume and customer traffic in 
the store. When prices are unusually high, customers often 
reduce their store purchases and some retailers struggle with 
credit line limits.
    Most PMAA member companies are rack buyers. In the 
industry, wholesale product is loaded at terminal racks and 
there are approximately 1,200 terminals in the U.S. Companies 
permitted to load product must have credit standing and a 
plethora of State, local and Federal licenses and permits. I 
will focus most of my testimony on what factors influence 
wholesale rack prices and how they impact petroleum marketers.
    When examining the EIA data over the past 15 years, it's 
crystal clear that crude oil price benchmarks (WTI) are the 
primary drivers of wholesale gasoline and diesel prices. 
Because of their importance, PMAA has been and remains an 
ardent support of CFTC regulations to improve transparency in 
futures markets.
    It is sobering to note that for every dollar increase in 
crude oil prices per barrel increase, that translates into a $2 
billion daily increase for gasoline and diesel prices on U.S. 
motorists.
    Additionally, PMAA supports completion of the Keystone 
Pipeline. We think the pipeline is important because it would 
diminish OPEC's cartel power to dictate crude prices. Further 
in the event of a conflict in the Middle East, we'll be 
thankful to have crude oil supplies readily available from 
Canada.
    The second driver of refined product prices are environment 
laws and regulations. With over 30 boutique fuel prices, or 
fuel recipes, bottlenecks can develop that dramatically 
increase the prices at the pump on a regional basis.
    Of course, most of you are aware of the escalating debate 
ongoing in Congress about the Renewable Fuel Standard. Because 
gasoline demand has been weak, refiners have few options to 
meet the ethanol mandate in 2014, so I'm not sure how it will 
affect prices.
    There has been much written and said about E15, but you 
need to know that E15 cannot meaningfully help solve the blend 
wall problem in the short term. We estimate there are 700,000 
gasoline dispensers in use in the U.S. and only 5,000 have been 
approved for E15, and I'm only talking dispensers. There are 
also underground tanks and underground lines that have not been 
approved for E15. It will require many years and lots of money 
to upgrade 160,000 gas stations to handle E15; one estimate I 
saw was $3 billion. Many of our member companies have 
significant investments in ethanol blending and would love to 
offer E15, but they simply cannot easily resolve the liability 
infrastructure problems.
    A few months ago, a major investment bank on Wall Street 
predicted ethanol RINs will go to $3 next year, and that will 
likely significantly increase gasoline prices over what they 
would normally be. We are urging the EPA administrator to 
adjust the ethanol mandate as needed to ease potential economic 
harm.
    In April 2007, several refineries in the Midwest, all 
serving the same region, were closed for maintenance. The price 
shocks in Minnesota, South Dakota and North Dakota were so 
severe, Senator Dorgan authored an amendment to the 2007 energy 
bill for EIA to have a coordinator to improve communications. 
It is now 6 years later and Congress has not appropriated funds 
for that position. Ironically, just 2 months ago, the same 
region was hit with a similar situation. For most of May, 
motorists in North Dakota, South Dakota, Minnesota paid 40 to 
80 cents a gallon more as a result of the refinery problems. We 
hope you will support funding.
    Last, I have to mention credit card fees. Interchange fees 
imposed on gas stations is not a cents per gallon charge, but a 
percentage of the total. When Minnesotans were paying $4.50 a 
gallon in May, if they were using their Visa credit card, they 
were likely paying 11 cents a gallon to Visa. Now the Federal 
gasoline tax is 18.4 cents, but you've got to build and 
maintain roads with that. Visa gets 11 cents a gallon for what? 
To make matters worse, Visa charges interchange fees on Federal 
excise taxes, so they get a cut on that as well. We continually 
believe credit card fees need to be addressed.
    Thank you very much.
    [The prepared statement of Mr. Gilligan follows:]

  Prepared Statement of Dan Gilligan, President, Petroleum Marketers 
                 Association of America, Arlington, VA
    Chairman Wyden, Senator Murkowski and distinguished members of the 
committee, thank you for the invitation to testify before you today. I 
appreciate the opportunity to provide some insight into factors 
impacting motor fuels prices.
    I serve as President of the Petroleum Marketers Association of 
America (PMAA). PMAA is a federation of 48 state and regional trade 
associations representing more than 8000 petroleum marketing companies 
nationwide, the majority of which are small businesses as defined by 
SBA. These companies are very diverse but all have one thing in common, 
they all bring to market liquid fuels such as gasoline, diesel, heating 
oil, ethanol, biodiesel, jet fuel and kerosene. Our member companies 
are engaged in the transport, storage and sale of petroleum products on 
both the wholesale and retail levels. They supply gasoline to 
convenience stores, diesel to truck stops, lubricants to industry and 
heating oil to millions of customers. Not only are these companies 
primary suppliers of fuels they also own and/or operate over 80,000 
retail facilities in the U.S. They also are often specialists serving 
farmers, railroads, marinas and airports with the fuels they need.
    The U.S. motor fuels production and distribution system is 
extremely complex and is therefore misunderstood and inaccurately 
characterized by many. I am hoping we can provide some unique insights 
to the committee today. An example of misunderstanding we deal with 
every day relates to gas station ownership. Over the past 12 years, the 
major integrated oil companies have dramatically reduced their direct 
retail operations and have sold those businesses to petroleum marketing 
companies. Of the 160,000 U.S. retail gasoline locations, over 94 
percent are now owned by independent businesses. When I joined PMAA in 
1998, 70 percent of the Shell stations in the U.S were owned by Shell. 
Today nearly all Shell stations are owned by independent petroleum 
marketing companies.
    Petroleum marketing companies do not benefit from high gasoline or 
diesel prices. Because they operate in such a transparently competitive 
environment, higher wholesale prices must be absorbed by retailers 
until street prices catch up. Thus, rising gasoline prices not only 
burden motorists, but petroleum marketers as well. In order to remain 
competitive, retailers usually offer the lowest price for gasoline to 
generate volumes sold and customer traffic inside the convenience 
store. When gasoline prices are unusually high, customers often reduce 
their purchases of convenience items. Additionally when prices are 
high, some retailers struggle with credit line limits.
    Another factor most PMAA member companies have in common is most 
are ``rack buyers''. In the industry, wholesale product is loaded at 
``terminal racks'' and there are approximately 1200 terminals in the 
U.S. Access to the terminal racks is quite restricted. Companies 
permitted to load product at terminals must have a plethora of state, 
local and federal licenses and permits. Also, they must have credit 
terms with refiners which is crucial for trade to function.
    Because PMAA member companies are ``rack buyers'', I will focus 
most of my testimony on what factors influence wholesale rack prices 
and how they impact petroleum marketers and consumers.

          1) The Price of Crude Oil

    The price of crude oil is the primary driver of wholesale gasoline 
and diesel prices accounting for 67 percent of the price per gallon in 
May 2013.
    A recent phenomenon in the oil markets is the price spread between 
the Brent crude oil contract and the light sweet WTI crude oil 
contract. Historically, the West Texas Intermediate (WTI) contract was 
the dominate price benchmark for the world, but since 2011, the North 
Sea Brent crude oil contract has taken over as the dominate benchmark. 
The sweeter, light crude WTI oil contract delivered in Cushing, 
Oklahoma was $2--$3 higher compared to the Brent contact and now it's 
common to see the Brent contract price $10--$20 above the WTI contract, 
although, in recent days that spread has narrowed to less than $5.
    Because Bakken and Eagle Ford oil shale developments are delivered 
to Cushing, Oklahoma, they put downward price pressure on the WTI 
contract, but only have a modest impact on the world's oil prices 
because the WTI crude oil is landlocked and doesn't have an outlet to 
the world oil market. However, this doesn't take away from the fact 
that the U.S. must continue to pursue domestic oil production to 
prevent future oil price shocks and limit OPEC's power to dictate 
price.
    As I mentioned earlier, crude oil prices often directly correlate 
to rack prices. Since crude prices are the prime factor, PMAA believes 
it is a duty of the U.S. government to make sure crude futures markets 
are honest markets with high levels of transparency. We believe both 
the WTI and Brent contracts can be vulnerable to excessive speculation. 
Since some of the U.S. market is likely priced off of Brent, the 
Commodity Futures Trading Commission (CFTC) should be examining the 
price discovery and fundamentals of the Brent contract. The graph* 
below shows the spread between WTI and Brent. Only until 2011 did the 
massive spread start occurring.
---------------------------------------------------------------------------
    * All graphs have been retained in committee filse.
---------------------------------------------------------------------------
    Congress also directed the CFTC to pass rules limiting certain 
commodities traders' size in energy commodities traded on and off 
exchanges where energy commodities are traded daily. The goal was to 
prevent investors from flooding cash into commodities and inflating 
prices. Large purchases of crude oil futures contracts by speculators 
have, in consequence, created an additional paper demand for oil which 
drives up the prices of oil for future delivery. This has the same 
effect that additional demand for contracts for the delivery of a 
physical barrel today drives up the price for oil on the spot market. 
Basically, a futures contract bought by a speculator has the same 
effect on demand for a barrel that results from the purchase of a 
futures contract by a petroleum marketer. The very definition of cash-
settled contracts as ``look-alikes'' means that what occurs in the 
financially-settled markets directly affects what occurs in the 
physical market.
    Final implementation of the CFTC's position limit rules was to have 
gone into effect on October 12, 2012 (for spot month position limits). 
However, on October 1, 2012, the U.S. District Court of DC ruled in 
favor of the Plaintiffs (International Swaps and Derivatives 
Association, etal) on the new speculative position limits rule. PMAA, 
the New England Fuels Institute (NEFI) and other members of the 
Commodity Markets Oversight Coalition filed an amicus brief in support 
of the CFTC's efforts to appeal the position limits ruling. PMAA 
cautiously supports the Commission's final rulemakings on margin/
capital requirement for OTC swaps and registration of unregulated 
exchanges which will reduce leverage in the marketplace that will 
benefit end-users and other market users from excessive price 
volatility and extreme price increases at the terminal rack. The final 
CFTC rulemakings will give end-users better price information because 
it will force swaps dealers to real-time reporting which will bring 
competition to the swaps markets.
    Additionally, PMAA has joined with other petroleum industry 
organizations in urging the President to immediately approve the 
Keystone XL pipeline which will contribute towards limiting OPEC's 
cartel power and ability to dictate price. Further, in the event of 
geopolitical conflict, we will be thankful to have the supply from our 
friends in Canada.

          2) Environmental Regulation (including the Renewable Fuels 
        Standard ``RFS'')

    There are over 30 boutique fuels in the United States. Boutique 
fuel blends in states differ including reformulated gasoline (RFG) and 
fuels with different levels of low Reid-Vapor-Pressure (RVP) ranging 
from 7 psi to 8--15 psi in standard conventional gasoline. Some states 
mandate RFG blended with ethanol (an oxygenate) while some states 
mandate low-RVP fuels blended with ethanol. As a result, these boutique 
fuels requirements create supply botttlenecks, and, in most 
circumstances, supply shortages foster higher prices.
    Additionally, passage of the ``Energy Independence and Security Act 
of 2007'' (EISA) was designed to spur the development and production of 
these alternative fuels, most notable of which is the 36 billion gallon 
renewable fuels standard (RFS). Under the EISA, blenders, primarily 
refiners and terminal operators earn marketable credits for each gallon 
of ethanol they blend into gasoline. The credits are traded among 
refiners in order to meet their annual renewable fuel volume blending 
mandates established by the EPA.
    Lately, the value of ethanol credits have increased in value and a 
number of factors play into this recent rise. As the ethanol blendwall 
approaches due to the barriers of E15, RIN values have skyrocketed 
because obligated parties are buying all of the available RINs to 
comply with the law. Eventually, refiners could resort to exporting 
gasoline or cutting back production to fall within the parameters of 
the RFS blending mandate, so they don't violate the law. Actions like 
this could lead to rack price chaos unless EPA lowers the corn-based 
ethanol mandate which PMAA supports lowering the level achievable with 
an E10 blend and reasonable growth for E85. PMAA does not oppose E15 
but advises marketers to obtain knowledgeable legal and regulatory 
counsel before offering E15 at wholesale or retail.
    The biggest barriers to E15 include:

   Gasoline retail infrastructure equipment is certified to 
        dispense and store up to 10 percent ethanol by Underwriters 
        Laboratories (UL). Without UL approval, very few retailers will 
        offer E15.
   Auto manufacturers extend warranties on existing vehicle 
        fleets up to 10 percent ethanol. Most have not been willing to 
        amend their warranties to handle blends above 10 percent 
        because tests have shown E15 could damage engines, fuel pumps 
        and other system components. This position did not change after 
        EPA approved E15 for 2001 and newer vehicles.
   PMAA is also concerned that if an owner of a pre-2001 
        vehicle misfuels with E15, the retailer would be held liable 
        for damage to engine and emission system components.

          3) Regional refinery utilization and/or outages

    Recent planned and unplanned refinery outages have also impacted 
rack prices. Scheduled maintenance at the BP Whiting Refinery in 
Indiana and at the ExxonMobil Joliet Refinery in Illinois (which both 
are now back up and running) has played a role in decreasing the supply 
of gasoline and increasing costs in the North Central region of the 
country. Furthermore, unplanned outages at HollyFrontier refineries in 
Cheyenne, Wyoming and El Dorado, Kansas and the Citgo LeMont Refinery 
in Illinois have contributed to the tightening of supply and higher 
rack prices. It's unfortunate that unplanned and planned outages 
occurred simultaneously, but there are ways to alleviate this 
occurrence. Currently, federal anti-trust laws prevent refiners from 
communicating with each other, so in other words, refiners don't know 
when another one will have scheduled maintenance performed. Section 804 
of the ``Energy Independence and Security Act of 2007'' Coordination of 
Planned Refinery Outages, assigned the Energy Information 
Administration (EIA) Administrator to review information on refinery 
outages from commercial reporting services and determine what affects 
they have on price, production, retail and wholesale supply shortages 
and disruptions while giving the Secretary of Energy the authority to 
encourage reductions of the quantity of refinery capacity that is out 
of service at any time. However, due to lack of EIA funding, the EIA 
terminated this program. PMAA supports dedicated funding for the EIA to 
restart this program to improve industry and government communications 
and planning.
    In 2012, East Coast refinery closures also had an impact on rack 
prices. Because those refineries had to buy light, sweet crude oil 
imported from Africa and the North Sea that was priced at a premium to 
the WTI contract, those refineries were put at a competitive 
disadvantage. Additional factors included declining demand for refined 
products, cumbersome environmental regulations and permitting processes 
which made refiners' plans to maintain or expand production capacity 
more difficult than necessary.

          4) Pipeline disruptions

    Rack prices are also impacted by refined product pipeline 
disruptions. Our nation's pipelines do a great job of getting product 
where it is needed but pipeline equipment sometimes fails or needs 
maintenance. If pipelines reduce service for any reason, regional 
shortages can develop. For instance, following Hurricane Katrina, the 
Colonial pipeline which consists of more than 5,500 miles of pipeline 
delivering a daily average of 100 million gallons of gasoline, home 
heating oil, aviation fuel and other products to key terminals and 
distribution centers along the East coast was taken offline after 
losing electricity to power pumps.

          5) Regional national disasters

    Hurricanes Katrina and Rita showed how vulnerable the United States 
is to natural disasters and Superstorm Sandy only reinforced the need 
to have effective planning before, during and following a disaster. 
Because the sequence of events following a natural disaster are often 
similar in terms of access to fuel supplies, PMAA has organized a task 
force that is examining the bottle necks and making recommendations to 
federal and state governments to streamline the process. Weather 
forecasting has become extremely accurate in modern times. We usually 
know where and when a storm will hit and some waivers could be 
implemented before the storm and not days later. Federal, state and 
local governments are in the position to alleviate supply disruptions 
during a disaster by waiving RFG and RFS requirements, weight limits, 
regional fuel specifications, IRS fuel tax regulations specific for 
dyed/undyed products, regional hours of service waivers among 
additional waivers that are needed to ensure sufficient flow of product 
during emergencies.
Additional Factors that Influence Retail Motor fuels prices
          1. Credit/Debit Card Fees

    Credit card companies and card issuing banks impose unjustified 
costs on gasoline and diesel consumers. They often demand payment of 2-
3 percent interchange fees on motor fuel transactions. In many cases, 
the card companies and banks make more off selling a gallon of gasoline 
than a retailer. While debit card fee reform was addressed in the Wall 
Street Reform Act (P.L. 111-203) under the Durbin amendment, credit 
card interchange fees keep escalating. In 2012, interchange fees were 
the second largest expense item for motor fuels retailers costing 
retailers $11.1 billion.
    PMAA was pleased with passage of the Durbin amendment to limit 
debit card interchange fees. However, the Federal Reserve's final rule 
to implement the law fell short of our expectations even though the 
Fed's biannual report on interchange fees found that the average cost 
to process a debit transaction was five cents. Prior to the Durbin 
amendment, debit interchange fees averaged 44 cents, and now, since the 
Durbin amendment was passed, they average 21 cents. The Merchants 
Payments Coalition (MPC) noted that the report proved that the Fed's 
final rule was flawed and the cap on debit card fees should be reduced. 
Much more needs to be done to bring down interchange fees and promote 
relief to consumers, particularly excessive credit card interchange 
fees which the Durbin amendment did not address.
          2. Taxes

    The Federal Government imposes a tax of 18.4 cents on each gallon 
of gasoline, and the States levy an average tax of 22 cents on each 
gallon. This does not account for all State and local taxes, such as 
sales taxes, which can range from 7.5 to 37.5 cents per gallon across 
States.
Conclusion
    It remains important for the U.S. to adopt policies that will 
reduce the power of OPEC and to increase U.S. job opportunities and 
strengthen the U.S. economy. Increased domestic production of crude and 
realistic renewable fuels mandates are key policy initiatives the U.S. 
should pursue as we move towards energy independence in the future. 
However, not even all alternative energy sources combined will provide 
the amount of energy required to run a $15 trillion annual economy 
until far in the future. For the next 100 years, we believe traditional 
sources of domestically produced crude oil will be needed to maintain 
the nation's economic and national security.
    Again, thank you for the opportunity to testify before the 
Committee today. I'll be happy to answer any questions you may have at 
this time.

    The Chairman. Thank you very much.
    Let's go now to Mr. Plaushin.

STATEMENT OF CHRIS PLAUSHIN, DIRECTOR, FEDERAL RELATIONS, AAA, 
                         HEALTHROW, FL

    Mr. Plaushin. Thank you, Chairman Wyden, Senator Murkowski, 
members of the panel.
    As the Nation's largest motoring group, when gas prices 
rise, we hear from drivers who are increasingly frustrated and 
who often to AAA for explanation. For more than a dozen years, 
AAA has provided an accurate and comprehensive resource, AAA's 
Fuel Gauge, which tracks national, State and local gas prices. 
Additionally, AAA educates the public on steps they can take to 
get more miles out of a gallon of gasoline. We view our role as 
arming consumers with factual information and unbiased 
perspective. Unlike others that frequently comment on the 
gasoline pricing, AAA has no involvement in the regulation, 
refining, shipping, blending or sale of gasoline. We seek to 
educate consumers on the factors that result in price swings 
and urge policymakers to find solutions that will result in 
more stable and more predictable prices.
    AAA has called on the Federal Government policymakers and 
other industry stakeholders to work to make sure that gasoline 
prices and supplies are stable and less subject to large 
fluctuations.
    It's difficult for many Americans to predict, understand 
and ultimately adjust to price changes that are regional, 
sudden and dramatic, as has often been the case in recent 
years. There are a host of factors that can impact the price at 
the pump. They range from the local variety, a pipeline 
disruption in Wisconsin, or heavy storms in the Great Plains, 
as we experienced this year; global variety, such as the unrest 
we've seen in Egypt this year. Factors range from the expected, 
seasonal demand changes, shifts in summer and winter blending 
requirements, and to the unexpected, hurricanes and refinery 
outages and other geopolitical tensions.
    The result of these myriad factors is a new normal. The 
days of a national pump price below $3 is likely a thing of the 
past, and State and regional price spikes that see retail 
prices move sharply in a span of days are now all too common. 
The national average hasn't been below $3 per gallon since 
2010, but since that date, motorists in 16 different States 
have registered a 1-week spike of at least 25 cents.
    Looking at 2013, the national average price for a gallon of 
gasoline on January 1 was $3.29, and this is the highest ever 
to begin the year, but they've also peaked earlier and lower 
than previous years. In 2011, the peak was $3.98 on May 5; in 
2012, the peak was $3.94 on April 5. This year, the peak came 
at $3.78 on February 28, and following that, the national 
average declined steadily to the recent low of $3.47 on July 7, 
but as we have seen, wholesale gasoline prices have followed 
crude oil prices higher in recent weeks. The prices at the pump 
in the majority of States is again on the rise, and barring an 
unforeseen market development, is likely aimed higher through 
the end of the summer driving season into mid-September.
    The rise and fall of the national average during the first 
half of 2013 was obscured by the high degree of State and 
regional price volatility, most notably on the West Coast and 
in the Midcontinent. In both of these cases, even as national 
average price of gasoline was falling, refineries that were 
offline for planned or unplanned maintenance meant a tightening 
of regional supplies and subsequently, sharply higher prices 
for drivers. While pump prices in these markets did drop 
sharply as production came back online, motorists are 
understandably frustrated and squeezed, and these dramatic 
price swings underscore the volatility that has become all too 
familiar in recent years.
    Unfortunately, there is no silver bullet solution to the 
high prices or market volatility that consumers are 
experiencing. The Federal Government should adopt a national 
energy policy which combines increased production, the 
efficient use of traditional and alternative fuels, elimination 
of lengthy roadblocks to the development of new sources of 
energy, so long as we are not precluding the appropriate level 
of environmental review.
    AAA remains committed to providing our members and the 
traveling public with accurate prices and fuel conservation 
tips. While much attention has been given to the production 
side of the equation, there is a demand aspect as well. 
Informing consumers must be a necessary element in any 
strategy, and how you use your car is just as important as 
which vehicle you choose to use.
    Thank you, Mr. Chairman, for the opportunity today. I look 
forward to any questions you might have.
    [The prepared statement of Mr. Plaushin follows:]

Prepared Statement of Chris Plaushin, Director, Federal Relations, AAA, 
                             Healthrow, FL
    Thank you for the opportunity to testify at today's hearing. My 
name is Chris Plaushin, and I serve as the Director of Federal 
Relations for AAA.
    AAA is a not-for-profit, fully taxpaying federation of motor clubs 
in the U.S. and Canada, providing more than 53 million members with 
travel, insurance, financial and automotive-related services. Since its 
founding in 1902, AAA has been a leader and advocate for the safety, 
security and mobility of all travelers.
    The price of gasoline is a primary concern of U.S. motorists and 
for more than a dozen years AAA has provided an accurate and 
comprehensive resource--AAA's ``Fuel Gauge''--which tracks national, 
state and local gas prices. Additionally, AAA educates the public on 
steps they can take to get more miles out of a gallon of gas.
    As the nation's largest motoring group, when gas prices rise we 
hear from drivers who are increasingly frustrated and who look to AAA 
for explanation.
    We view our role as arming consumers with factual information and 
unbiased perspective. Unlike others that frequently comment on gasoline 
pricing, AAA has no involvement in the regulation, refining, shipping, 
blending or sale of gasoline. We seek to educate consumers on the 
factors that result in price swings and urge policy makers to find 
solutions that will result in more stable, predictable prices. AAA has 
continuously called on the federal government, policy makers, and other 
industry stakeholders to work to make sure that gasoline supplies are 
stable and not subject to large fluctuations. Oil is a publically 
traded commodity and influenced by the ebbs and flows of the market 
just like any other product subject to the forces of supply and demand.
    AAA knows that consumers are frustrated by the pinch of higher 
retail gas prices. It is even more difficult for many Americans to 
predict, understand, and ultimately adjust to price changes that are 
regional, sudden and dramatic, as has often been the case in recent 
years.
    There are a host of factors that can impact the price of gas at the 
pump. These range from the local variety--a pipeline disruption in 
Wisconsin or heavy storms in the Great Plains--to the global--violence 
in the Middle East and North Africa or economic growth in China. They 
also range from the expected--seasonal demand increases, product shifts 
or rising global demand--to the unexpected--hurricanes, refinery 
outages or geopolitical tensions.
    The result of these myriad factors is a ``new normal'' where the 
days of a national pump price below $3.00 is likely a thing of the past 
and state and regional price spikes that see retail prices move 
violently in a span of days are more common. The national average 
hasn't been below $3.00 per gallon since 2010 and motorists in 16 
states have registered a one-week spike of at least 25 cents since that 
date.
    The national average price for a gallon of gasoline on January 1 
was $3.29 per gallon--the highest mark ever to begin a year. As has 
been the case in recent years, prices rose to begin 2013, however they 
peaked earlier and lower. In both 2011 and 2012 gas prices rose to 
start the year because of surging oil prices due to unrest in the 
Middle East and North Africa. In 2011 the national average peaked at 
$3.98 per gallon on May 5. In 2012 it peaked at $3.94 on April 5 and 6. 
In 2013 the price peaked at $3.78 on February 28 and 29. From that 
peak, the national average declined steadily to a recent low of $3.47 
on July 7. As wholesale gasoline prices have followed crude oil prices 
higher in recent weeks, the price at the pump in the majority of states 
is again on the rise and is likely aimed even higher--barring an 
unforeseen market-moving development--through the end of the summer 
driving season in mid-September.
    Obscured by the relatively orderly rise and fall of the national 
average during the first half of 2013 was the high degree of state and 
regional price volatility due to refinery disruptions, most notably on 
the West Coast and in the Midcontinent. In both of these cases, even as 
the national average price of gasoline was falling, refineries that 
were offline for planned or unplanned maintenance meant a tightening of 
regional supplies and subsequently sharply higher prices for drivers. 
While pump prices in these markets did drop sharply as production came 
back online, motorists were understandably frustrated and squeezed by 
soaring prices and these dramatic price swings underscored the 
volatility that has become all too familiar in recent years. The most 
expensive gas prices in the country are, as of July 12, paid by drivers 
in Hawaii ($4.32), Alaska ($4.05), California ($3.99), Connecticut 
($3.84) and Washington ($3.84). Drivers pay the least in South Carolina 
($3.21), Alabama ($3.30), Mississippi ($3.30), Tennessee ($3.32) and 
Arkansas ($3.35).
    Unfortunately, there is no ``silver bullet'' solution to high 
prices or to market volatility. Rather it will take a portfolio of 
polices to best mitigate the periodic uncertainty of gas prices and 
their impact on consumers.
    The federal government should adopt a national energy policy, which 
combines increased production, the efficient use of traditional and 
alternative fuels, and the elimination of lengthy roadblocks to the 
development of new sources of energy--so long as we are not precluding 
the appropriate level of environmental review.
    Going forward, from AAA's perspective, such a plan should strive to 
seek an effective balance between our need for mobility and 
independence and our need for increased energy efficiency.
    AAA remains committed to providing our members and the traveling 
public with accurate prices and fuel conservation tips. While much 
attention has been given to the production side of the equation, there 
is a demand aspect as well. Informing consumers must be a necessary 
element in any strategy--how you use your car is just as important as 
which vehicle you use.

    The Chairman. Mr. Plaushin, thank you.
    Mr. Khan.

STATEMENT OF FAISAL KHAN, MANAGING DIRECTOR, CITI RESEARCH, NEW 
                            YORK, NY

    Mr. Khan. Thank you.
    Chairman Wyden, Ranking Member Murkowski, and distinguished 
members of the committee, my name is Faisal Khan and I am a 
managing director at Citigroup, working in the Equity Research 
Department. My primary responsibilities include the fundamental 
research and analysis of the integrated oil refining and 
pipeline industries in North America. I am honored to be here 
today to discuss this important topic.
    The U.S. refining industry has evolved and restructured 
over the last 20 years. Currently, 70 percent of U.S. refining 
capacity is owned by the independent refiners compared to 40 
percent 15 years ago. The industry has evolved to be one of the 
largest industrial manufacturing sectors in the U.S. from one 
simply tied to primary energy production 2 to 3 decades ago. It 
is characterized by a high degree of competition with both 
domestic and foreign independent refining companies, integrated 
oil companies and national oil companies competing to deliver 
gasoline to the U.S. market. Therefore, gasoline prices in the 
U.S. remain tied to the global markets, adjusting for the cost 
of transportation.
    There are a number of key trends that have been and 
continue to develop in the U.S. fuels and primary energy 
production sectors of North America. First, after peaking 
during the middle of the last decade, gasoline demand appears 
to be in secular decline. We estimate we could see gasoline 
demand reduced by 600,000 barrels a day through the decade, 
simply from the CAFE standards in place. High sustained oil 
prices, and therefore, higher gasoline prices compared to 
earlier in the last decade, is resulting in price elasticity.
    Second, while dissolute demand, diesel, jet fuel and 
heating oil should see constructive global demand growth in the 
decade, the situation in the U.S. is evolving, with heating oil 
demand being replaced by cheap natural gas supply, and natural 
gas beginning to compete with diesel for short-haul trucks and 
potentially long-haul trucking, we estimate up to 50 percent of 
long-haul truck sales could be CNG or LNG by 2025, assuming the 
price difference between natural gas and oil remains in place. 
This scenario could result in the displacement of roughly 1.8 
million barrels a day of diesel demand in the U.S. over the 
next 15 to 20 years.
    Third, on the supply front, both natural gas and oil 
production are growing in the lower 48. Canadian oil production 
also continues to grow. We estimate U.S. and Canadian oil 
production could grow by 5 million barrels a day through this 
decade. The growth in lower 48 production which began in the 
middle of 2008 has resulted in significant price discounts on 
both Canadian and U.S. crude versus global benchmarks of 
between 20 percent and 40 percent; however, as more logistics 
capacity has been added, we've seen a moderating of these 
differentials more recently.
    Fourth, the growth in oil supply is resulting in a record 
build out of pipeline, rail and marine infrastructure to deal 
with the changing flows of crude oil in the U.S. and Canada. 
Despite the delay in the Keystone Excel Pipeline, the industry 
is working around the issue. Crude oil movements by rail have 
grown exponentially over the last few years and look to 
continue to grow. Pipeline bottlenecks in the Midwest and South 
are being unlocked with new and expanded infrastructure. As 
more domestic crude arrives in the Gulf Coast by pipeline and 
other coastal markets by rail, regulations such as the Jones 
Act increase the cost of delivering crude to U.S. ports and 
potentially increase the price of gasoline, most notably on the 
Eastern seaboard. The result of increased crude by rail could 
result in more safety incidents. According to third party data, 
rail has 4 times the incident rate than pipelines.
    Fifth and still related to supply, the ethanol continues to 
grow; however, gasoline demand continues to contract in the 
U.S., pushing the mandate toward the blend wall. As the 
committee knows, refiners meet their mandate through the RIN 
system. Currently, there are winners and losers in the RIN 
market. As we move into next year, we estimate the liability to 
the industry could grow, pushing RIN prices up and potentially 
impacting gasoline prices as refiners try to pass on the cost 
to the RIN through the market. The RIN market is thinly traded 
with relatively few participants when compared to other 
commodity markets. Unless the supply of RINs increases, either 
through more E15 sales or a reduction in the mandate, we see 
RIN prices continuing to rise into next year.
    To sum up our comments, the growth in hydrocarbon 
production is positive for the U.S. economy. It has put the 
independent refining industry on the low end of the global cost 
curve, resulting in a massive increase in exports. 
Infrastructure is being built out to deal with production 
growth, resulting in job growth and higher economic activity. 
The crude oil and products market appear to be functioning 
normally and providing the right incentives, which we estimate 
will push the U.S. into energy independence by the end of the 
decade. Regulatory hurdles such as the delay in Keystone Excel 
and higher RIN costs add friction to the market. Nevertheless, 
the industry appears to be able to work around these issues 
with a higher cost in doing business.
    Again, thank you for the opportunity to testify. I look 
forward to answering any questions you may have.
    [The prepared statement of Mr. Khan follows:]

 Prepared Statement of Faisel Khan, Managing Director, Citi Research, 
                              New York, NY
Opening Remarks
    Chairman Wyden, Ranking Member Murkowski, and distinguished members 
of the Committee, my name is Faisal Khan and I am a Managing Director 
at Citigroup working in the Equity Research Department. My primary 
responsibilities include the fundamental research and analysis of the 
integrated oil, refining and pipeline industries in North America. I am 
honored to be here today to testify on how U.S. gas and fuel prices are 
being affected by the current boom in domestic oil production and the 
restructuring of the U.S. refining industry and distribution system.
Independent Refiners
    Historically, refineries have been considered part of the 
integrated oil supply chain. As oil was discovered, producers felt the 
need to integrate their supply with the product market (gasoline and 
distillate) through refineries and retail stations. However, as the 
industry became increasingly competitive over the last few decades, 
there has been less of a need to be integrated. The result has been the 
emergence of a major independent refining industry.
    While the refining industry is clearly attached to the energy 
industry, the mechanics of the industry are more like other industrial 
and manufacturing sectors in the US rather than primary energy 
producers. Generally, independent refiners do not have control over 
their input costs and product prices. Refiners are price takers on both 
ends of the barrel. Their costs, crude oil, are priced in the global 
market and the products, gasoline and diesel, are similarly priced. We 
therefore look at the independent refining industry as a major 
industrial sector that is deeply cyclical and deeply seasonal 
(seasonality of gasoline and diesel demand). Margins and not the 
notional price of crude oil drive their profitability.
Industry Background
    For almost the entire decade of the 1990's refiners did not make 
their cost of capital and actually destroyed value for shareholders. 
There existed a tremendous amount of overcapacity in the system 
throughout all the 80's and most of the 90's. During this time, 
capacity was rationalized and demand grew steadily bringing the market 
into balance by the time of the millennium.
    Starting in 2000, global refining capacity began to tighten. Major 
oil companies began to shed their refineries after major consolidation. 
Environmental costs also escalated as gasoline specifications became 
more rigid. During this time, independent refiners grew their market 
share. In 1998, 40 percent of refining capacity in the US was 
controlled by the independents. By 2008, this number had grown to 60 
percent and today stands at 70 percent following the spin-off and sale 
of a number of refining assets from integrated and major oil companies.
    The refinery shutdowns in the 80's along with growing fuels demand 
during the 90's in the US, China, Asia, the Middle East and Brazil 
brought refining supply and demand into balance in 2000. However, just 
as we turned to a new millennium, oil supply began to disappoint as 
many OPEC countries did not deliver on new supply to the market. 
Therefore, just as refining was coming into balance, oil prices started 
to rise, pushing gasoline prices to levels that had not been since the 
late 70's.
    During most of the last decade (2000-2010), refiners earned healthy 
margins as overall global refining utilization approached 90 percent 
(2006). Generally speaking, the industry requires 15 percent extra 
capacity for adequate supply of fuels to take into account major 
turnarounds and downtime in the industry.
    The high utilization rate was a result of solid growth in gasoline 
and distillate demand during this decade (2000-2007) resulting in solid 
refining margins in 2004, 2005 and 2006. The high margins were a direct 
market signal to national oil companies, major integrated oil companies 
and independent refiners to bring more capacity to market. In this 
effort, there began a push to expand capacity across the entire world 
with the US, Asia and Middle East building new capacity. At the same 
time, renewable fuels such as ethanol began to enter the supply pool 
through the renewable fuels standard (Renewable Fuels Standard as part 
of the 2007 Energy Bill passed in December 2007). So on the supply 
side, we began adding more refining capacity and ethanol supply just as 
the world was about to go into a major recession.
    On the demand side, the high price of oil (hitting nearly $150 per 
barrel in 2008) became a tax on the consumer resulting in some price 
elasticity in 2007-2008 (wholesale gasoline prices were $3.52 per 
gallon in the middle of 2008 or about $4.25 a gallon at the pump). 
Furthermore, increased CAFE standards in the US and demand for more 
fuel efficient cars from global consumers became a headwind for demand. 
We currently estimate gasoline demand could contract by a further 600 
mb/d through the end of this decade just using the current CAFEs 
tandards.
    With the world in the midst of a major recession in late 2008, all 
of 2009 and part of 2010 (wholesale gasoline prices dropped to $1.00 
per gallon in early 2009 or about $1.75 per gallon at the pump), 
increased supply of refined product from new capacity and ethanol 
caused the industry to fall on difficult times with many questioning 
whether some companies would remain solvent.
    In 2010, 2011 and for part of last year, refiners began shutting 
down older, less competitive refineries in order to improve the supply 
demand balance of refined products in the global markets. Capacity was 
shutdown in the US, Europe and Japan. Even today capacity continues to 
be shut in Japan, Australia and North America. Furthermore, the delay 
in new refining capacity in Latin America, the shutdown of European 
refining capacity and a solid economic recovery in Latin America caused 
refined product (both diesel and gasoline) exports out of the US to 
surge.
    The recent surge in exports has certainly opened a new avenue of 
business for domestic refiners. For most of the last decade (2000-
2007), product exports from the US to other parts of the world remained 
fairly range-bound between 900mb/d to 1.2mmb/d. Imports of refined 
product were in fact much higher at 2.1mmb/d. However, following the 
great recession and the increase in fuel efficiency in the US, our 
country had too much refining capacity and these refineries needed to 
find other markets for their product or risk being shutdown. At the 
same time, the market expected refining capacity in the US to get 
rationalized because newer capacity in Asia was threatening to push 
more refined products into the US. However, lower natural gas prices 
and therefore cheaper hydrogen enabled US refineries to move down the 
global cost curve to become more competitive. The US is now exporting 
between 2.6-2.9mmbls/d of refined products--more than doubling exports 
to the rest of the world. Last year, product imports were 640mb/d.
The Hydrocarbon Production Boom in the US & Canada
            US Production
    The discovery of shale gas in the US during the last decade by US 
independent oil and gas companies resulted in robust natural gas supply 
growth over the last several years. These new discoveries were the 
result of a technology shock. New methods in natural gas extraction 
resulted in a significant increase in supply and therefore a large 
reduction in domestic natural gas prices. During most of the last 
decade, natural gas prices in the US were higher than that of Europe 
(2000-2010). This changed with the discovery of shale gas which made US 
energy intensive industries highly competitive, refining included. We 
estimate natural gas supply could grow 10 percent-15 percent through 
the decade.
    The technology advancements in shale gas began to spill over into 
oil in the last five years. The industry figured out how to access oil 
from shale and tight formations more economically. This technology 
combined with high sustained oil prices resulted in increased oil 
production from unconventional sources of oil. Oil production has now 
grown by 2.8 mmbd since bottoming out at 4.4 mmbd in 2008. The Bakken 
is a clear example of the technological break through with production 
growing from 300 mbd to 780 mbd over the last few years. The Eagle Ford 
in South Texas, the Niobrara in Colorado, the Utica in Ohio, the 
Permian in New Mexico and Texas and finally the Monterey in California 
are all shale formation and/or basins that are or could contribute to 
the continued growth in oil production. We estimate total US crude oil 
production could reach 9.0 mmbd by the end of this decade (currently 
7.3 mmbd).
Canadian Oil Production
    Over the last several years, oil production in Canada has grown 
while Canadian refinery demand has remained flat, driving increasing 
exports into the US, mainly into the Midwest. In the next 18-36 months, 
heavy-sour Canadian crude should make its way via new pipelines to the 
US Gulf Coast in increasing abundance, while a surplus of heavy-sour 
crude from Canada should move from the US Midcontinent to the US Gulf 
Coast. We estimate this increased supply from Canada will put pressure 
to back out medium and heavy crude oil imports from Saudi Arabia, Iraq, 
and Kuwait in the Middle East as well as Venezuela, Colombia and Mexico 
in Latin America. In order for the Middle East and Latin America to 
maintain market share in the US, they may have to discount their crude 
to remain competitive.
    We estimate Canada could grow liquids (oil and NGLs) production 
from nearly 3.5 mmbd today to 6.5mmbd by the end of the decade. 
Canada's liquids production is a mix of oil sands, sythentic, 
conventional, shale and natural gas liquids. Oil sands is the main 
source of Canadian production growth through the decade. We expect oil 
sands production will contribute about 200 mb/d of growth every year 
for the next 10, perhaps 20, years. Canadian oil sands production could 
grow +1.9-mmb/d to 3.7-mmb/d from the end of 2012 to 2020. 
Infrastructure bottlenecks were impacting producer economics for most 
of 2012 and early this year, however, the discounts on Canadian crude 
have narrowed more recently with the ramp up of rail volumes out of 
Western Canada and seasonal downtime.
    Takeaway capacity from Canada into the US has been challenged with 
the delay of Keystone XL and other pipelines running at below capacity 
from the Canadian border to the Midwest. However, producers appear to 
be shifting their production to rail and have been more aggressive 
lately in signing up for alternate pipeline takeaway capacity both in 
the US to debottleneck the Midwest and Midcontinent as well as move 
crude East through a partial conversion of the Canadian Mainline 
(natural gas). While a potential pipeline from Alberta to the Pacific 
has always been a goal of producers and pipeline developers, it appears 
political friction between British Columbia and Alberta could put those 
aspirations on hold forcing more crude to move:

          1. by rail to the Canadian coastal markets for export;
          2. into the US Midcontinent through the debottlenecking of 
        pipeline capacity (not including Keystone XL); and
          3. by a new pipeline to the Canadian East Coast (Mainline 
        conversion).

    Based on this analysis, the markets appear to be working around the 
delay in Keystone XL. Therefore a delay of the pipeline is unlikely to 
affect crude oil production growth out of Canada.
Crude Oil Production Growth Impact to Oil Markets
    With the sustained growth in crude oil from the lower 48 and 
continued production growth in Canada, the markets were caught off 
guard in 2011 and 2012. There was not enough logistics takeaway 
capacity (both pipeline and rail) to evacuate all the crude being 
produced in the interior US and Canada. Furthermore, the delay in 
infrastructure to move Canadian crude to the Gulf Coast only 
exacerbated the situation. Much of this new production ended up in 
inventory in Cushing and other facilities through PADD II (Petroleum 
Administration for Defense Districts).
    During 2011 and 2012, only 250 mbd of pipeline takeaway capacity 
(Cushing to Gulf Coast) was added to alleviate the bottleneck against 
1.5 mmbd of production growth (US crude oil production). The 
combination of crude oil production growth and the lack of logistics 
capacity resulted in interior US crude oil benchmark pricing (WTI--West 
Texas Intermediate) trading to substantial discounts to international 
Benchmark oil prices (such as Brent oil, priced in Northwest Europe).
    At the peak of the bottleneck, the benchmark US interior crude oil 
price (WTI) traded at $28 per barrel discount to waterborne prices 
(Brent). Canadian crude price discounts actually faired much worse at 
over $40 per barrel versus similar waterborne crudes.
    With pipelines taking longer to get done, rail quickly picked up 
the slack with producers and refiners now moving nearly 400,000 car 
loads (annualized for 1Q'13) of crude oil this year compared to 9,500 
car loads in 2008 (according to the Association of American Rail 
Roads). Producers and pipeline owners have been working on new projects 
to alleviate the bottlenecks. Large pipeline companies have been 
working with Canadian producers to find new ways around the constraints 
that existed in 2011 and 2012. Smaller US pipeline companies have been 
working with producers in the lower 48 to move crude to the Gulf Coast. 
These projects are just starting to contribute to crude oil being 
evacuated to the coastal markets resulting in the continued reduction 
in crude oil imports. From 2005 to 2013, US imports of crude oil have 
nearly been cut in half (graph below*).
            All figures have been retained in committee files.
    The refining industry has seen a massive shift in its crude 
purchases. The industry used to move crude by tanker from international 
sources and then by pipeline into the interior US. Almost all this 
international crude has stopped moving into the Midcontinent, Midwest 
and Rockies refining systems. It has been replaced by domestic and 
Canadian crude. Pipelines that used to run crude from the Gulf Coast to 
the interior US have had to be reversed and many existing pipelines now 
run at reduced capacity.
    The benefits of these crude discounts mostly flowed to interior US 
refining capacity which makes up about &20 percent of total US 
capacity. However, as we've seen more recently, these discounts have 
compressed. Market signals allowed producers, refiners and pipeline 
developers to bring more logistics capacity to market.
    With more crude now hitting the Gulf Coast from the interior US by 
pipeline, differentials are starting to collapse. Canadian crude is 
also making its way to the Gulf Coast by barge and in small quantities 
by pipeline. With international crude prices holding firm, interior US 
benchmarked crude have finally caught up in the last nine months moving 
from $88 per barrel in 4Q'12 to $105 per barrel last week. 
International benchmark crude oil prices are actually down. At these 
prices, we continue to see US and Canadian producers highly 
incentivized to grow production. Citi's view is that continued growth 
in North American oil production will put pressure on international 
benchmark prices.
    In Citi Research's view, pipeline and tanker shipping constraints, 
such as the Jones Act, only serve to slow down the influence of US oil 
production growth on the global oil markets. Furthermore, the higher 
shipping costs of Jones Act tankers has the effect of increasing 
gasoline prices particularly in the Northeast where product imports are 
critical in meeting demand. In our view, pipelines and tankers continue 
to be the safest and most efficient means to deliver crude to market 
with rail used as a medium to deliver crude from stranded locations or 
to refineries that may not have access to pipeline or port capacity.
    Aside--Shipping crude or product from the US Gulf Coast to ports on 
the East or West Coast falls under the Jones Act, which would require 
that the goods be carried on US flag vessels, constructed in the US, 
owned by US citizens and crewed by US citizens and permanent residents. 
There are very few US flagged vessels available for these purposes.
    According to the Manhattan Institute of Policy research, moving 
crude by rail and truck have much higher incident rates than pipelines. 
Rail has almost 4x the incident rate and road has almost 40x the rate 
of pipelines.
Crude Oil Exports
    With US imports of crude oil continuing to fall, we are already 
starting to see the constraints on the refining complex's ability to 
absorb all the light sweet crude being produced in the US. Over the 
last two and half years we have seen price discounts on domestic crude 
oil of over 20 percent as a result of volumetric constraints on the 
logistics systems. However, we could be entering a period of quality 
constraints as US refiners reach their maximum intake of light sweet 
crude. We believe we are seeing this in the Gulf Coast where Eagle Ford 
crude is now being shipped from Corpus Christi to Eastern Canada.
    We estimate the Canadian Northeast has the ability to consume up to 
800 mb/d of US light sweet crude. Crude can be shipped from the US to 
Canada by a non-Jones Tanker. Furthermore, because Canadian crude has 
no export constraints, producers are most likely to export crude out of 
Canada at better netbacks rather than compete with US crude that will 
be shipped to the Canadian Northeast at discounts to global benchmarks.
    Other export outlets potentially exist to Mexico and to countries 
with which the US has free trade agreements with. Singapore and Korea 
are countries the US has a free trade agreement with and have large 
refining industries.
Gasoline and Distillate Markets
    With crude oil production clearly on a trend to grow, the question 
has often been asked: Why is all this production growth not driving 
down gasoline prices? Since the US still imports crude oil and exports 
refined product, US refined product prices are connected to global 
gasoline and diesel markets (minus transportation). In addition, crude 
oil prices in the US are likely to remain linked to global markets 
minus the cost of transportation and logistics. We estimate it would 
take several more years for the US to reach crude oil independence 
without significant substitution affects.
    For the last few decades, global product prices have remained 
linked with prices in Asia generally being higher than that of the US 
and Europe.
    With US gasoline consumption continuing to decline, excess gasoline 
production has been moving increasingly to Latin America. Given the 
limited amount of new refining capacity coming on line, we see the US 
continuing to deliver more gasoline to Latin America. Over the last ten 
years, product demand in Latin America has grown by over 150 mb/d per 
annum.
    Higher exports are a critical ingredient to the vitality of the US 
refining industry. As we've discussed, US refiners now have significant 
advantages when compared to their global counterparts. Lower natural 
gas prices in the US relative to the rest of the world and growing 
crude oil production put US refineries on the high end of the global 
margin curve. Of the 500 refineries across the world that we detail on 
the margin curve below, the vast majority of US assets show up in the 
top quartile.
Crude Oil and Refined Product Market Threats
    The rise in crude oil prices and therefore refined product prices 
over the last decade have resulted in global oil consumption reaching 
10 percent of global GDP, which represents one of the highest levels 
we've see in more recent history.
    The higher cost of crude and advent of new technology is resulting 
in the substitution of natural gas and electricity for crude oil in the 
US. We see this in the chemical industry where naphtha is being 
substituted out of the US chemical crackers in favor of ethane and 
propane (derivatives of natural gas production). US chemical 
manufactures now show up on the bottom of the cost curve.
    We are also seeing a substantial amount of heating oil (distillate) 
demand destruction in the Northeast and Mid-Atlantic where home owners 
are switching from heating oil to natural gas. This momentum has the 
potential to substantially reduce the almost 500mbd heating oil market 
that exists in the US today.
    The other clear threat to the refining industry is the substitution 
of natural gas and electricity in the transportation sector. We are 
starting to see heavy duty vehicles move to natural gas. Citi estimates 
50 percent of all refuse trucks sales are now CNG vehicles. And while 
the long haul trucking fleet has seen very little penetration by 
natural gas vehicles, Citi estimates up to 50 percent of heavy duty 
vehicle sales could be LNG and/or CNG by 2025. This assumes the current 
price difference between natural gas and oil carries forward into the 
next decade. Under this scenario, up to 1.8mmbd of distillate demand 
could be displaced.
    We view the market penetration of natural gas into the light duty 
vehicle fleet to be somewhat limited. However, we do see an opportunity 
for electric vehicles to make up 3 percent of global vehicle sales by 
the end of this decade. Plug-in vehicles could make up another 3-4 
percent of vehicles sales by 2020. Next generation electric vehicles 
could raise this market share.
The Impact of Regulation on the Industry
    There are a number of key regulatory issues that have an effect on 
the refining industry. These issues include:

          4. Environmental costs. This may include the cost of 
        compliance with changing gasoline and distillate 
        specifications, emissions standards and carbon costs.
          5. Government Mandates. This includes the renewable fuels 
        mandate and cost of renewable identification numbers.
          6. Construction Permits. This includes permits to build 
        pipelines and expand or retool refining capacity; and
          7. Trade and shipping restrictions. This may include crude 
        oil export permits and the Jones Act.

Environmental costs
    Many of the fuel specification changes over the decade are now 
fully capitalized in the current assets of the US refiners. Many other 
countries are also following some of the US standards. The cost of 
carbon is an unknown quantity for the industry. The state of California 
is moving forward with its low carbon fuel standard (LCFS) program. 
Carbon credits in California have more than doubled over last year 
trading near $70/ton. This is a much higher price than Europe and could 
threaten the competitiveness of the industry.
Government mandates
    The renewable identification numbers (RINs) has taken the industry 
by surprise this year. 2013 ethanol (D6) RIN prices have increased from 
7 cents/gal in early March 2013 to $1.10/gal this month. Blenders are 
hitting the ``blend wall'' but are still required to fulfill the RFS 
obligations which are higher than the ``wall''. The RFS-2 (the latest 
targets from 2007 legislation) mandates 13.8-bn gal (900-k b/d) of 
ethanol be blended into the gasoline pool in 2013. But with US gasoline 
demand at 8.7-m b/d in 2012 and declining due to higher vehicle 
efficiency standards, this places the blend wall at around 870-k b/d 
(13.4-bn gal).
    We believe the RFS mandate had envisioned increasing gasoline 
demand. However, higher vehicle efficiency standards in the US are at 
odds with the RFS mandate. As we get closer to 2014, the RIN liability 
is likely to grow and it is not clear if higher RIN prices will be 
passed along to the retail gasoline price.
    Current penalties for non-compliance are high at $32,500 per day 
per RIN. Refiners have some flexibility to carry a 20 percent deficit 
into the following year. One solution could be to increase the 
availability of E15 or E85 (increasing RIN supply), however the wide 
adoption of a new fuel might be difficult given the potential corrosion 
issues to model year cars built before 2001 (11/4/10 EPA report and 
www.epa.gov/otaq/regs/fuels/additive/e15 ) and product liability issues 
associated with retail distribution. Currently &20 retail stations 
provide E15 in 6 states out of &121,000 retail gasoline stations across 
the entire US. According to Citi Research's Agriculture analyst, corn 
inventories are expected to reach surplus levels for crop year 2013/
2014, which would result in the cost of ethanol being much lower than 
gasoline (all else being equal) providing a market incentive for 
additional E15 stations.
    We believe there are currently both winners and losers in the RIN 
market today, which is mitigating the impact of the RIN cost to the 
consumer. However, we envision a situation next year when refiners and 
marketers exhaust the RIN ``bank''. Under this situation, the entire 
market would be short RINs. Under this scenario, RIN prices would most 
likely be passed along to the consumer and wholesale gasoline prices in 
the US could be higher than the rest of the world. Therefore without 
the addition of more RINs to the market, the price of RINs could soar 
resulting in higher gasoline prices in 2014.
    Our research shows that higher RIN prices this year will impact the 
profitability of refiners by between 5-15 percent. Refiners that do not 
blend their own gasoline production are clearly most at risk.
    Aside--Buying and selling of RIN credits revolves around three 
distinct counterparties in what is a highly illiquid and esoteric over-
the-counter (OTC) market. Obligated parties (OP)--refiners and 
importers--that are subject to statutory requirements set by the EPA 
are the largest components of market trading (physical and paper). Pure 
blenders that mix ethanol or biodiesel with traditional fuels are 
another source of RIN demand (physical and paper). Non-commercials are 
newer market participants which speculate on price direction and to a 
degree might be construed as `liquidity providers' willing to hit a bid 
or lift an offer in an otherwise one-sided market (paper).
Construction Permits
    The two issues refiners and pipelines are dealing with are permits 
for new pipeline construction and CO2 permits to increase or 
retool refining capacity to absorb more light sweet crude into 
refineries' crude slates.
    The Keystone XL pipeline is a new pipeline project that has faced 
unprecedented delays. I have covered the pipeline industry for 12 years 
and I have never seen such a long delay in pipeline construction as we 
have seen for Keystone. In our opinion, the delay in Keystone will not 
stop crude production growth in Canada and the US. The decision to 
delay Keystone only allows other mediums of transportation such as 
rail, barge and trucking to be more widely used. Furthermore, the delay 
only forces producers to look at alternate pipeline routes to deliver 
crude to market. As more Canadian crude gets delivered to the coastal 
markets, it will enter the global market and the US could lose a 
dedicated supply source. Finally, as more crude ends up on the rail 
systems of North America, the law of numbers suggests we are only 
likely to see more incidents. We believe the unfortunate incident that 
we observed in Quebec is a reminder of the consequences of moving 
increasing amounts of crude by rail.
Trade restrictions
    As crude oil production grows and fuels demand subsides in the US, 
we at Citi Research believe Congress may very well have to address the 
issue of crude exports. Separately, the Jones Act has clearly become an 
impediment to moving new US crude to the coastal refineries that could 
use it. It also has the affect of increasing gasoline and diesel prices 
in the US because of the added cost of transportation. Moving crude and 
products from the Gulf Coast to the West Coast and East Coast requires 
the use of Jones Act tankers. The cost of moving crude by Jones Act 
tanker could be 3.0x to 6.0x the price of using non-Jones Act tankers. 
As we previously discussed, Canadian East Coast refineries are now 
delivering crude from the Gulf Coast to Canada's Northeast at much 
lower rates than tankers that could deliver crude to the US Northeast.
Closing Remarks
    Thank you for the opportunity to testify before you today on these 
important issues. I look forward to answering any questions you may 
have.

    The Chairman. Thank you very much, Mr. Khan. I want to 
thank all our witnesses. We have had 10 Senators come in and 
out on a hectic morning, so we're just going to go back and 
forth and I believe it's going to be possible to just keep 
things going.
    Let me start with the question of why the lower cost of new 
oil supplies is not being passed on to the consumer. I want to 
start with you, Mr. Sieminski, using a chart from the Energy 
Information Administration.
    The chart shows that, on average, 67 percent of the cost of 
a gallon of gas at the pump is the cost of the oil that goes 
into it, and for diesel, that's 62 percent. Now the second 
chart that I want to hold up shows what industry leaders call 
the crack spread. That's the difference in price between what a 
refiner pays for crude oil and the price a refiner gets for 
selling the gas and the diesel fuel it makes. Now this chart 
was based on an analysis that was done for the committee and I 
ask unanimous consent to insert this Congressional research 
service analysis in the record without objection, and that will 
be done.
    The Chairman. Now the refineries in the Midwest and the 
Rockies, what are called Pad 2 and Pad 4, which have access to 
the lowest cost oil from North Dakota and Canada, have the 
biggest margins: $39 a barrel compared to $14 a barrel on the 
East Coast or $25 on the West Coast. Those are the annual 
averages. In some months, for some refiners, the spread in Pad 
2 and Pad 4 has been considerably higher, in the $40 and $50 
range, roughly a dollar a gallon, 42 gallons, of course, in a 
barrel of oil. So we are talking about record-level refining 
margins. Let me repeat that, record-level refining margins, and 
while they are not all profit, certainly, a lot seems to be, 
though the flipside of this part of the story is that lower 
crude oil costs from these new sources of production aren't 
being passed through to the consumer.
    So Mr. Sieminski, to begin, why aren't consumers seeing the 
benefits of these lower crude oil prices when two-thirds of the 
cost of a gallon of gas is the cost of the oil that is used to 
make it?
    Mr. Sieminski. Senator, the purpose of that graphic of the 
gasoline pump is to try to provide some illustrative knowledge 
to any user of EIA's data as to how the price of gasoline has 
to include the cost of inputs like crude oil and ethanol, as 
well as refining and distribution margins and State, local, and 
Federal taxes, so we try to provide some breakdown for that.
    If you come back to the basics of your question, virtually 
every group that I know that's ever studied product markets 
believes that product prices are being set in the global 
market, so the price of gasoline in a sense is a global price, 
it's not a local or regional price in the U.S. So what that 
means is that if there are lower crude prices in the Midwest 
region of the U.S., that is going to be reflected in refining 
margins, as your chart illustrates. So what the difference in 
price does allow is some ability of those refiners to begin to 
upgrade their facilities to do things like make better use of 
the light sweet crude oil that's being produced. One thing that 
I do want to say is that I think consumers are benefiting from 
the growth in domestic oil production; the 2 million barrels a 
day or so that we've seen just in the last few years has added 
to global supplies. Increases in oil production from any source 
around the world, including from the United States, tend to 
hold oil prices down. In your opening remarks, you talked about 
prices having reached $147 a barrel back in 2008. I think that 
it's fair to say that spare capacity in OPEC, which was very 
low back in that time period, is rising because of increased 
U.S. oil production; that means that international oil prices 
are lower and consumers are probably benefiting, and if they 
were $21 lower, that would be 50 cents a gallon of gasoline 
lower in prices that consumers are benefiting, if you could say 
that international prices are $20 lower.
    The Chairman. My time is about up, Mr. Sieminski. Let me 
perhaps just ask it in this context: having been on this 
committee for a long time, we've always been told that the 
price of gas is related to the price of oil. My sense is, based 
on this kind of evidence that we're seeing, that may no longer 
be necessarily the case.
    Mr. Sieminski. It's related to the international price of 
oil.
    The Chairman. We're going to be asking about that in the 
context, because my time is up, about Keystone as well. I just 
am troubled with the basic proposition that really questions 
what we've been told around here, and that is when you have new 
oil supplies the consumer at the pump is supposed to benefit, 
and we're not seeing that in too many instances and we'll 
explore that.
    Senator Murkowski.
    Senator Murkowski. Let me just continue on that vein 
because in my opening statement, I alluded to the belief that 
increased American oil production or domestic production here, 
which I mentioned, is up 30 percent over the past 5 years, has 
reduced or at least restrained prices at the pump; we can 
speculate as to what it might be, but it's been my contention 
that we've at least been able to hold it down.
    Mr. Sieminski, you have clearly indicated that you would 
agree with that statement. I'd ask the rest of you if you agree 
with where I'm coming from on it; do any of you think that 
supply is irrelevant to the market price that we're seeing? Any 
disagreement there? OK, I will take that as assent.
    Let me ask about the issue of what we're seeing with these 
spiking RIN prices. I think a lot of us are concerned about 
what we're seeing here. I've written several letters to the EPA 
about the issue, asking for some kind of a plan of action, or 
at least a background on what has prompted this rise.
    Mr. Klesse, in your comments, you mentioned that Valero may 
see $750 million increase this year alone due to the spike in 
RIN. I guess I'd ask you, I'd ask Mr. Khan as well, because you 
have mentioned this: you say that the RFS is broken, that it's 
out of control, Mr. Klesse. Mr. Khan, you have mentioned that 
the RIN prices at 35 cents a gallon could cut refiner's margins 
by 5 percent to 15 percent this year. Explain to the committee, 
if you will, where we are going with prices to, not only to the 
refiners, but ultimately then, to the consumer if we are not 
able to get this under control, to use your terminology, Mr. 
Klesse. Mr. Khan, if you would also comment.
    Mr. Klesse. So the obligated party under the program is 
refiners and importers. As was mentioned, gasoline demand has 
been falling, so now it's flat, but down a lot from the 2007 
law. So because we're the obligated party, we can only blend up 
to E10; that's the accepted in the marketplace, car warranties; 
it is a well-accepted product. We do have some E85 in the 
market; however, when the law was passed, the amount of ethanol 
is going up and it is increasing every year. Because we're at 
E10, you cannot--in the amount of gasoline in the marketplace--
you are not able to blend to the mandated volume. Now we are an 
obligated party as importers.
    Blenders are not the obligated party. Blenders generate the 
RIN. So you have the situation where we are a large merchant 
spot market seller of gasoline. Because we do that, we have 
then to have a RIN because we have a renewable volume 
obligation. We have to go by that. Blenders generate the RIN. 
To level the playing field, it should move to blenders should 
be the obligated party, it would be a level field; however, 
that would still not solve this difference between a mandated 
volume and the blend wall, and then going to E15 just does not 
make any sense for the consumer; car warranties do not approve 
it, so you would be asking us, besides the pump question and 
other questions, to sell a product that actually is not 
approved by the car warranties.
    Senator Murkowski. Let's go to Mr. Khan.
    Mr. Khan. Thank you.
    There are 2 pieces of legislation that are causing this 
situation to happen; the first is the RFS mandate, which 
initially envisioned higher gasoline demand for the foreseeable 
future, so we were able to increase the amount of renewable 
fuels into the gasoline pool. The CAFe standards envision sort 
of declining gasoline demand, so you have 2 opposing pieces of 
legislation that are causing what we call a short position to 
take place in the RIN market. So as we get into next year and 
as we've passed the blend wall, what we end up seeing is this 
increasing short position and liability that refiners end up 
with, and that in theory can be passed along to the retail 
buyer of gasoline as refiners try to pass on the cost of RIN in 
producing gasoline into the market.
    Senator Murkowski. My time is expired, but Mr. Khan, have 
you updated your numbers to reflect the impacts that we can see 
if the RIN remains at the current price of above a dollar?
    Mr. Khan. No, we haven't, so in our testimony, we stated 
that it could impact the earnings of the refiners that we cover 
by 5-15 percent--that was at a much lower RIN price. Certainly, 
RIN prices have moved up; those costs could certainly move much 
higher than what we have in our numbers.
    Senator Murkowski. Thank you. Mr. Chairman.
    The Chairman. Thank you, Senator Murkowski. I believe we 
have time to get into questions or our next senator, Senator 
Baldwin. As I say, we're just going to try to keep this going. 
Senator Baldwin.
    Senator Baldwin. Thank you, Mr. Chairman, and I want to 
start by thanking you, Mr. Chairman and Ranking Member 
Murkowski for such a warm welcome to the committee. I'm 
delighted that my appointment to this committee has coincided 
with 2 hearings that, last week and this week, that are so 
incredibly relevant to my home State of Wisconsin.
    On the topic of today's hearing, it's particularly timely 
for people that I represent in Wisconsin. Residents of 
Milwaukee saw gas price changes over 60 cents per gallon during 
the month of June. I want to go into a little bit more depth on 
a topic that a number of you referenced in your formal 
testimony of refinery outages.
    The Energy Information Administration has attributed the 
recent price hikes in the Midwest to refinery outages. Analysis 
by the Federal Trade Commission concluded that the planned 
shutdown of a refinery adds 2 to 7 cents per gallon to the 
price of gasoline and in the event that it's an unplanned 
outage of a refinery, it can be twice that amount.
    We also know that recent planned outages put an unnecessary 
squeeze on prices when multiple refineries go offline at the 
same time, as has happened in the Midwest. Meanwhile, the 
impact on consumers who are planning their budgets, their tight 
budgets, month to month, planning on their travel needs, and 
businesses that are trying to predict their expenses, this is 
extremely disruptive to them. We've heard through testimony and 
discussion of these temporary outages that they were the result 
of a lack of information, a lack of transparency, and I think 
we should be able to do better. So I'd like you to perhaps 
touch it in greater depth than you did in your opening 
testimony of what information gathering and planning can be 
done in a transparent way to make sure that consumers aren't 
bearing the cost of these kind of refinery outages, the planned 
ones that we saw earlier this year. I know there is policy in 
the 2007 Act that the information collection has stopped in 
recent years, there's issues of funding for that role; if you 
could please elaborate, I know that my constituents are eager 
to hear.
    Can we start with you, Mr. Sieminski.
    Mr. Sieminski. Sure. Thank you, Senator Baldwin.
    First of all, you're absolutely right, and back to Senator 
Wyden's concerns about gasoline prices, EIA found recently in a 
study that we published on our Today in Energy page that 
gasoline prices for consumers are reflecting the highest 
percentage of their budget that they have all the way back to 
the 1980s, so it's a very high price that consumers are paying 
and it definitely is impacting their budgets.
    On the Federal Trade Commission study, what the FTC found 
was that the length of time, that planned outages tend to occur 
in the spring and fall when margins are typically low, the 
length of time since the last plant turnaround is generally 
associated with more unplanned outages, so if you try to delay 
repairs to meet the exigencies that come up, it can make things 
worse. It's pretty clear that outages have an impact on 
gasoline prices and it's worse when utilization rates are high.
    EIA was asked by law to develop a report from commercially 
avilable information on planned refinery outages, so we had a 
report that we did twice a year just ahead of the turnaround 
seasons in February and in the fall. What we found was that 
that report, although it helped provide some information, 
really wasn't sufficient to enable consumers or anybody else to 
manage the pricing situation. We had to stop doing that because 
of a huge budget cut that EIA suffered in 2011 and we just had 
to rank the things that we were doing in priorities, and if we 
could do an analysis of planned and unplanned outages, I think 
it would help us understand the markets better. I'm not sure 
that it would completely address the situation of dealing with 
the volatility that's inherent in markets like these.
    The Chairman. Here's where we are: we have 3 of us who need 
to vote. I want to say, I'm going to work with the Senator from 
Wisconsin; she's making a very logical point about transparency 
and information sharing. Senator Barrasso is going to try to 
get a question or 2 in and he needs to vote, and we'll just see 
if we can keep this going and I thank my colleagues.
    Senator Barrasso.
    Senator Barrasso. Thank you very much, Mr. Chairman, and I 
have a number of questions. Perhaps with your permission, Mr. 
Chairman, I'll be allowed to submit these for the record.
    But I did want to ask Mr. Klesse, because you cited 
problems associated with the Renewable Fuel Standard, I've 
introduced legislation that actually repealed the entire 
Renewable Fuel Standards. You and Senator Murkowski both 
mentioned the higher RIN prices related to the fact that the 
Renewable Fuel Standard requires refiners to blend biofuels, 
specifically cellulosic ethanol, that is not in large scale 
commercial production and until refiners brought the EPA to 
court, the agency was levying fines on refiners for failing to 
blend a product that wasn't available.
    Could you just spend a little bit of time, how Valero 
arrived at the position that Congress should now repeal the 
Renewable Fuel Standard?
    Mr. Klesse. I do support that. We should repeal and start 
over. The situation is completely changed, as was highlighted 
on the panel. Gasoline demand, energy security, it's entirely 
changed.
    Senator Barrasso. You have a specific level of, I believe, 
additional credibility on this because of Valero having a 
number of different components of your markets.
    Mr. Klesse. Yes, and we are the third largest ethanol 
producer, and we actually do believe ethanol will continue to 
be part of the fuel mix; it's just this continuing drumbeat for 
more and more products that are nonexistent and if you think 
about it, there are implications. If we went to E15, it's going 
to corn-based driven, which sure, works in our interests, but 
there is some responsibility for food prices around the world.
    Senator Barrasso. Thank you, and I regret, I'm going to run 
and vote, too. There's only 2 minutes remaining and if we could 
just stand adjourned until Chairman Wyden returns. Thank you.
    [Recess.]
    Senator Cantwell [presiding]. The Senate Energy Committee 
will come to order. As our colleagues are returning from a 
vote, we're going to go ahead and start the hearing, restart I 
guess I should say, and thank you all for being patient for the 
vote, and Senator Franken is next and we'll let you go with 
your line of questioning. Senator Franken.
    Senator Franken. Thank you, Senator.
    First, I think it's been pointed out in testimony, there 
are many reasons for gas price volatility. Senator Baldwin 
brought up refinery closures; I think the Chairman gave me a 
bit of a shout out on keeping an eye on that, the need for more 
data on that, to be able to monitor that data, to coordinate 
those, so what happened in Minnesota didn't happen. There's 
geopolitical issues, hurricanes, speculation, supply demand 
factors, and I don't think it's fair to blame the Renewable 
Fuel Standard, which is the backbone of our renewable energy 
policy, and I don't think it's the time to attack the RFS when 
a number of cellulosic plants are expected to come online. The 
policy is helping to wean us off foreign oil and I think that 
is a good thing.
    Speaking of weaning us off of foreign oil, Mr. Sieminski, 
you testified, and so did Mr. Hume, to the dramatic growth in 
oil production in this country over the last several years. Can 
you tell us how much of this increase from onshore production 
is coming from shale and related type geological formations?
    Mr. Sieminski. Senator, we think that virtually all of the 
growth is coming from light sweet crude oil production that's 
being produced from the shale formations.
    Senator Franken. I think Mr. Hume would agree, and you 
spoke of this renaissance in oil production. Can you tell us 
whether hydraulic fracturing and horizontal drilling are the 
primary tools that you use to fracture these geological 
formations to get the hydrocarbons out?
    Mr. Hume. Yes, Senator Franken. The greatest thing that's 
made the changes is horizontal drilling. We've been fracture-
treating wells since before I was born. I grew up in Oklahoma 
and they were driving frack trucks in front of my home when I 
was very young, so hydraulic fracturing is not new, but 
horizontal drilling is, and it's allowed us to economically 
access low permeable rocks. It started with the shale, with the 
gas, and now we're in the tight carbonates and sandstones where 
we're finding this light tide oil and we have very repeatable 
opportunities to continue growing this source for the next 10 
to 20 years and beyond.
    Senator Franken. I'd like to point out to my colleagues 
that the reason we are seeing--and we all go back and read the 
testimony, we read the record very thoroughly, all the 
members--the reason we're seeing the dramatic increase in 
production is because as early as the 1970s, the Federal 
Government invested in the research and development that led to 
hydrofracking. Some of my colleagues frequently criticize the 
government's role in developing new technology, but as it turns 
out, the Federal Government played a huge role in developing 
the technology that is being used today in the Bakken Formation 
and in other areas.
    The Federal Government supported research and development 
of this technology as far back as the 1970s for the Eastern Gas 
Shales Project, and in fact, microseismic imaging, a critical 
tool used in fracking, was originally developed by Sandia 
National Laboratory, a Federal energy laboratory, and 
horizontal drilling as well.
    That's what we have been experiencing; that's the reason 
for this renaissance, is it not?
    Mr. Sieminski. That is correct.
    Senator Franken. Mr. Hume, can you tell me what fraction of 
shale oil resources in the Bakken Formation happen to reside on 
non-Federal lands, roughly speaking?
    Mr. Hume. I think it's a very small portion is on Federal 
lands; I would estimate less than 20 percent. The majority of 
the acreage that we hold is on private lands.
    Senator Franken. I think that's consistent with the data 
from the Center for Western Priorities, which found that around 
90 percent of all onshore shale oil and mixed oil and gas 
resources are found under non-Federal lands, so the reason 
we're seeing a bigger increase of production on private and 
State lands is really because that's where the majority of the 
shale resources are and that was technology, again, that was 
developed by the Federal Government.
    I see my time is up and I'll--back to Chairman Cantwell.
    Senator Cantwell. Thank you, Senator Franken, and I want to 
thank the Chairman and the Ranking Member for holding this 
hearing, it's a very important issue, and for all of you being 
here today.
    Obviously, high gas prices on the West Coast and supply and 
demand issues is something I've spent a lot of time on, my 
office has spent a lot of time on, and here we are again with 
prices approaching $4 per gallon in Washington State, and it is 
starting to--when it gets to that point, it starts to eat into 
our economic growth. So up 9 cents in the past week, Washington 
State prices are among some of the highest in the Nation--27 
cents above the national average--and a new report by 
McCullough Research confirms that, something we suspected all 
along, that during the past year, West Coast gasoline prices 
have ceased to follow the crude oil price. I mean, I think my 
constituents would get it if there was a supply and demand 
formula that they could follow here, but they can't follow one, 
so I'd like to enter into the record the report to illustrate 
some of the peculiar behaviors on the West Coast petroleum 
markets over the last year.
    The report also underscores the need for continued real 
oversight and investigation of refinery shutdown announcements. 
We found last year that in a West Coast refinery fire that 
everybody said, oh, well, this is the cause of the spike, when 
in reality, data showed that refineries weren't offline, but 
actually, were still emitting, which raised a lot of questions 
about who is actually following these markets and the 
transparence. I believe that EIA should play an even bigger 
role.
    But what we need to know now is what's caused these recent 
spikes. On October 1, a seemingly minor problem at Exxon 
Mobil's Torrance refinery led to an almost instantaneous 
increase in wholesale prices in California, adding up 50 cents 
in less than a week; a power problem that only briefly 
interrupted operations is supposedly blamed for one of the 
highest price spikes in a decade. Now I guarantee you, when the 
implosion happened in the Gulf, if prices would have spike that 
much, the Nation would have taken action, and so my question 
is, when these prices spike to this level--in both cases, crude 
oil prices were either level or falling and during the highest 
price spike, inventories were either increasing or remaining at 
a historic 5-year averages--so we're not following supply and 
demand here. My constituents very much want to see more 
transparency there. Mr. Plaushin, in your testimony, you 
mentioned the high degree of volatility due to refineries, and 
Mr. Gilligan, you cited reasons, but just as these shutdowns 
seem to be hitting the press, what do you think we need to do 
to get more transparency in the market?
    Mr. Gilligan. We supported Senator Dorgan's amendment in 
2007 to try to get EIA more involved in communicating about 
refineries, scheduled maintenance and outages. You know, 
really, it's the unplanned outages that really tear up the 
market. I think in the upper Midwest, there were 2 or 3 
refineries that were down for maintenance, and generally, that 
was understood, but then all of a sudden, you had, I think, a 
serious problem--a BP refinery in Whiting and then you had 
another refinery outage and all of a sudden, you had a 
catastrophe on your hands.
    We think we need to take baby steps to see what can be done 
to improve communication and planning so that people are more 
aware of what potential problems could be, so we're ready to 
sit down and talk with you and committee staff about what kind 
of things EIA might be able to do to help everyone accommodate 
those changes, the outages that are scheduled.
    Senator Cantwell. I mean, do you think that the country 
would have stood for, if we had the Gulf implosion and 
everybody being shut down, 10 other refineries in the United 
States saying, ``Oh, I had planned maintenance, so I'm going to 
go down.'' Do you think we would have put up with that?
    Mr. Gilligan. I think to some extent, and certainly Valero 
knows more about that than I do, but there's a life safety 
issue without it; they have to go down for maintenance or they 
could risk injury to their employees if they don't do the 
right--so you have to weigh that into it; it's not that simple 
and it can be very complicated.
    Senator Cantwell. Four or 5 refineries going down at the 
same time?
    Mr. Klesse. First off, Valero announces its turnarounds, 
planned turnarounds. We announce them, actually for the 
financial community, because they're very interested in them. 
There are also services that actually aggregate them and put 
them together, but I think your question was addressing more 
of--we have a spot situation and all of a sudden, the market's 
moved dramatically, and it's actually the expectation. Supply 
and demand is there, but it's the expectation, so when 
Torrance, in your example, had an issue or--and I'm not sure 
what's actually happened in Washington. When you have these 
issues because refiners are larger today, we have inventory in 
the system, but there's immediate expectation in the wholesale 
markets that then goes through to the retail markets of how 
long are they going to be down. Because this is a commodity, 
we're largely in balance in the system, so when some of the 
supply comes off, the expectation is going to be tighter and 
all of a sudden, you get prices moving, and then if you'll 
notice, over time, depending on getting it there, the prices 
come back down.
    Senator Cantwell. I think it's one of America's most 
important commodities and probably least regulated. Hamburger 
probably has more regulation on it than gasoline, and yet, the 
fact that this price spike can happen without real supply and 
demand issues is a problem that we have to address, and I see 
the Chairman has returned, but Mr. Khan, I wanted to mention, 
the fact that you bring up the Jones Act as something of a 
price increase, Citigroup has been under investigation and paid 
penalties, both for fraud in the mortgage market and is now 
under investigation by the FSA for manipulation in gas prices, 
and the fact that you come here and blame the Jones Act as some 
reason why we have high gas prices is just amazing to me.
    Thank you, Mr. Chairman.
    The Chairman [presiding]. Thank my colleague.
    Senator Stabenow. Thank you very much, Mr. Chairman, and we 
thank each of you for your testimony.
    I want to talk a little bit about biofuels as Chair of the 
Agriculture Committee, and I'll also just start by saying do I 
make the assumption that all of you would say free market 
competition is a good thing? Anybody disagree with that? OK. 
That competition brings prices down? That's how our free market 
system works and what we're trying to do in part is get more 
competition into the marketplace and we have a real dilemma 
going on, I think. On the one hand, the tax structure hasn't 
been competitive because we've seen oil incentives that started 
in 1916, they don't have deadlines, we don't renew them with a 
tax extender bill and every year, it's an ongoing effort, so we 
can plan and invest, it's served us well in an industrial 
economy, served my great State of Michigan well. I'm sure I 
would have supported those things; not the same thing on either 
biofuels or wind or solar or other technologies in terms of 
certainty, so you can invest and plan and so on for the future.
    What I see on the biofuels end and what I struggle with is, 
on the one hand, we see tax incentives that have been there 
almost a hundred years on oil; we see in the public interest, 
competing issues around CAFE, fuel economy, we want to bring 
fuel efficiency up, we want to bring the use of gasoline down; 
it's working, there's less gasoline, less demand for gasoline. 
We're trying to get more competition in in biofuels on behalf 
of the public, yet there's no pumps, and who owns the stations 
in order to get the pumps?
    We're told that the Renewable Fuel Standard doesn't work; 
the cost of RIN is certainly going up; not enough demand, but 
yet, we can't get more use and more competition because the 
infrastructure is owned by folks that, I mean, in all fairness, 
why would you want the competition, right? It's your job to 
control the market and not have competition, so we're at odds 
here on how do we move forward on all of this. So, I would just 
say for the record, I mean, it's important to note that since 
2005 when the Renewable Fuel Standard was created, 75.8 billion 
gallons of ethanol has been added to the gas supply; it cuts 
demand for foreign crude oil and gasoline; biofuel production 
reduced the need for imported oil by 462 million barrels last 
year alone; it seems to me, that's in the public interest, 
understanding all of these other issues, blend wall, what's 
happening and so on.
    So, Mr. Klesse, I would just start with you because you've 
said that Valero is currently investing in renewable fuels and 
alternatives, and I'm wondering both what role you see these 
technologies in the company's future, but also, given your 
interest in biofuels, are you encouraging station owners to 
install biofuel blender pumps?
    Mr. Klesse. Of course, we would, but we own no stations, so 
we don't own any; they're all owned by independents--I'm not 
sure of the percentage that are small, individual or small 
companies, but they're not the big oil companies that own the 
gas stations--they're not.
    Senator Stabenow. What would you say to encourage then? In 
order for us to get the infrastructure for real competition, to 
give this a chance to really show whether or not it works and 
what the public thinks and so on, I mean, how would you suggest 
that we move forward on infrastructure to make sure that we can 
have the pumps?
    Mr. Klesse. I'm not sure I understand exactly your goal, 
but if you'll let me----
    Senator Stabenow. Sure.
    Mr. Klesse. We already have E10 in about 95 percent of all 
the gasoline sold in the United States, so 10 percent ethanol. 
We are a big ethanol producer; we encourage that, we support it 
and we do it. It's our customers though for that 5 percent that 
don't do it, they don't feel like their customers, the ultimate 
consumer, wants it. We support E85; we'll gladly blend for 
people E85. We are not supportive of E15 for all the reasons 
that have been stated: car warranties, pumps, everything that 
goes with it, and over time, we'll see what happens.
    Senator Stabenow. No, I understand----
    Mr. Klesse. OK.
    Senator Stabenow. I understand from my own industry there 
are concerns. I have to say----
    Mr. Klesse. But Valero is very much in it and we are very 
supportive of renewable diesel as well.
    Senator Stabenow. Let me just say, Mr. Chairman, with E15, 
it's interesting--and I appreciate because our industry is very 
concerned about it--but I'm a NASCAR fan and when I go out to 
NASCAR, they drive on E15 and you should hear those guys talk 
about efficiency of E15 and what it does in terms of their 
performance on the track and so on, so it's very interesting.
    Mr. Klesse. Lots of octane; you have a lot of----
    Senator Stabenow. Lots of octane. That's right.
    I guess my question is, I mean, it seems to me, we have a 
real dilemma, and maybe let me ask Mr. Gilligan, on flex-fuel 
vehicles and on pumps and so on, if we had more flex-fuel 
vehicles, if we had blender pumps so that drivers could choose 
a lower cost fuel; I mean, do you think it would be a good idea 
if we had more of that and how would you suggest that we bring 
these fuels to market in a more efficient way?
    Mr. Gilligan. Certainly, it's been a limit to E85 to have 
the population of flex-fuel vehicles so disparate; they're so 
spread out, it doesn't make sense for a retailer to put in a 
E85 location if there aren't a lot of vehicles in his 
marketplace for it.
    Second, E85 customers notice that they have to fill up 
twice a week because of the reduced gas mileage, so that hurts 
E85.
    One other thing that I want to stress, too, about 
infrastructure is we spend a lot of time talking about 
dispensers, making dispensers capable of E15; we're concerned 
about all the stuff under the ground--the underground storage 
tanks, the piping, the glues that were used, how will those 
perform with a higher level of ethanol? We need more 
information about that. EPA is working on it. EPA and the 
Petroleum Equipment Institute are building a data base list of 
equipment that they say can handle E15. The problem for a 
retailer is he may not know what he has underground; he may not 
know what piping was put in 20 years ago and he may not be able 
to determine if it's compatible, so it's a real tangled web of 
issues.
    One estimate I saw is it would take about $3 billion to get 
a large portion of the gas stations able to dispense 15, E15. 
It certainly can't come from the convenience store owner; I 
think the average net profit of a convenience store is about 
$40,000 a year; you can't make the math work to spend $300-
400,000 in renovations when you're really close on the bottom 
line. So it's a perplexing problem, but we're committed to 
finding solutions, but they're not apparent yet.
    Senator Stabenow. Mr. Chairman, I know technically my time 
is up, but with the 2 of us just here, I'm going to just take 
another moment if you don't mind for a comment and just say, I 
know this is perplexing, but when we sit back from where we sit 
and we talk about where the money goes, where the tax 
incentives go, where the public interest is.
    I appreciate that we've had a industry that's dominated, 
we've incentivized it, talking about picking winners and 
losers, we picked a winner, you won; you know, it's a very 
important industry, but when we look at where we go in the 
future. I mean, there are options for us on how we incentivize 
real competition at the pump, and when we do tax reform and we 
look at one industry that has had unrestrictive tax incentives, 
others that limp along, can't invest, no dollars in incentives 
to do the kinds of things you're talking about; it's no 
question that a convenience store is not going to be in a 
situation to do that, but we've invested a lot of tax money, 
and continue on certain kind of industries, in certain areas 
where folks are doing very, very well--the top end, the top 5 
oil companies--I think we could redirect some of that to help 
some of those folks and it's in our interest to create 
competition and make the Renewable Fuel Standard work in a way 
that doesn't create this situation you're talking about, but it 
does involve thinking more broadly, Mr. Chairman, about 
consumer interest and competition, and I'm all for competition 
and I'm anxious, as I know you are, to make sure that we have 
the opportunity for lots of different choices on fuel at the 
pump, and I think that's our challenge.
    The Chairman. Your leadership on this, Senator Stabenow, 
has been extremely important and there's no question that this 
relates to marketplace forces; this ought to be something that 
brings together Democrats and Republicans, to have these 
choices, and I'm interested in working with you.
    Let me ask you gentlemen, again, about how we might help 
the consumer now; not some other time or have a big long fight 
in the Congress, but how we might help the consumer now with 
these price spikes that we're seeing, and price spikes that 
were related to these refinery outages.
    Mr. Klesse, to your credit, you're talking about how you 
all share that kind of information, you're interested in doing 
it. What if we just said when there was a planned or unplanned 
refinery outage, you had to report that in real time? I mean, 
it seems to me that could provide some measure of relief to the 
consumer. What do you think of that, Mr. Klesse? Just require 
it, a reporting requirement.
    Mr. Klesse. For planned, obviously, there would be a 
publication and so people would know that these are planned. 
They do happen in the spring and fall, they're usually 
scheduled; many of these get scheduled a year in advance for 
planned, and it has to do with safety, equipment, we do risk-
based analysis, we do all these kind of things.
    Now an unplanned, obviously, it's unplanned, and that means 
something happened right now and then this particular unit 
within a refinery goes offline. As far as reporting it, I can 
assure you, the industry press picks it up immediately, and all 
the commodity markets.
    The thing the Administration could do today to help 
prices----
    The Chairman. Right.
    Mr. Klesse. Is getting a hold of RINs. RINs are out of 
control, and we at Valero, we're trying to pass them through, 
and when you take a $1.30 RIN gallon, you go to E10--that means 
there is 13 cents a gallon that is trying to be passed through 
in the marketplace because as I said, that is a huge amount of 
money in aggregate.
    The Chairman. We are going to spend a lot of time looking 
at the RINs issue. Suffice it to say, we do need to get our 
arms around this refinery outage issue, and I know Exxon 
Torrance was picked up by the press and it wasn't done 
accurately, so it strikes me that this is something that could 
be done that would actually provide some real relief to the 
consumer, and Mr. Sieminski, I want to kind of walk through 
EIA's role on this.
    Now in 2007, the Congress directed EIA to track refinery 
outages and flag those that would have a significant impact on 
supply. In 2011, before you arrived, the Energy Information 
Administration stopped tracking the refinery outages. Why was 
that done and what would need to happen, Mr. Sieminski, to get 
that restored?
    Mr. Sieminski. Senator, in 2011, EIA's budget was cut 
overnight by $15 million, roughly 15 percent of our budget, and 
we had to very quickly prioritize the reports and analysis and 
data collection activities that we were engaged in, so we 
looked at the refining planned outage report, which was being 
done twice a year, and our conclusion was that private services 
that had been referred to earlier here were doing some of that 
and, given unplanned outages were the problem, that our money 
could be best spent doing other things that Congress has 
mandated.
    For example, recently, we've been reporting on Iran's 
production under the sanctions activities that Congress----
    The Chairman. Let me save some time here. Isn't protecting 
the consumer a priority, too? I mean, I just described 
misleading information that got out, expensive, misleading 
information. Why isn't protecting the consumer a priority there 
as well, particularly with something that strikes me as quite 
modest? I mean, we've had some pretty ferocious debates here in 
this committee over the years about price controls and 
burdensome requirements and the like; this seems to me a very 
modest step to make markets more transparent, to try to help 
the consumer in real-time--how much would this cost for you to 
get back in the consumer protection business?
    Mr. Sieminski. Several million dollars a year.
    The Chairman. All right. I'm going to follow this up and 
I'm going to walk through the sort of list of activities that 
you all have----
    Mr. Sieminski. Senator, I absolutely agree with you that 
more transparency in the data and analysis is essential; I 
wouldn't have taken the job at EIA if I didn't believe that, 
and I'd be happy to work with you on these issues.
    The Chairman. We'd like to and I want to really work with 
you looking at the context of the entire budget. I mean, 
certainly over the years, there have been antitrust and 
competition issues associated with refiners sharing information 
about maintenance and production schedules, but that's why the 
Congress brought you all in, and now we're seeing, particularly 
in the Midwest, what I think is the conventional wisdom in the 
energy business, which is why I walked through the charts with 
you, being turned on its head. I mean, people consistently in 
this committee have been told that the price of gas is related 
to the price of oil, doesn't seem to necessarily be true, and 
it certainly looks to us that the inability to get real-time 
information with respect to these issues, and particularly, 
outages, is an important one.
    So let me now turn to the question of exports, and let's 
bring up, staff, if you would, chart number 7.
    Now we'll bring Mr. Sieminski, Mr. Klesse and Mr. Khan into 
it. This is a chart that our staff produced from Energy 
Information Administration data that was provided on refinery 
capacity. So there's been a reduction in the number of 
refineries in the United States, although new investment in 
those remaining refineries has actually resulted in increased 
U.S. capacity; this comes at a time when the U.S. has demand 
for gas that has been declining. Now a number of analysts argue 
that the United States has surplus refinery capacity. Exports 
of refined products have been increasing dramatically, aided by 
relatively lower crude prices and lower natural gas prices, 
which give our refiners a cost advantage. U.S. refiners are 
exporting roughly 2.8 million barrels of product a day. The 
United States is even exporting refined products to Venezuela. 
The charts from the EIA show, again, the increase in gasoline 
and diesel exports, especially from the Gulf Coast. Now, for 
you all, to what extent do you see U.S. exports of gasoline and 
diesel continuing?
    Again, this goes back to a question for the consumer. The 
consumer is saying, as Senator Baldwin says, as I hear from 
Oregonians consistently, we're looking for some relief at pumps 
here in the United States, and yet, you all show up at these 
hearings in Washington, DC, talk about more and more exports--
tell us to what extent you see U.S. exports of gasoline and 
diesel continuing and/or expanding--and we can bring at least 
Mr. Sieminski, Mr. Klesse and Mr. Khan into this, but any of 
you witnesses who choose to comment are welcome to do so.
    Sieminski.
    Mr. Sieminski. Senator, we are forecasting that exports of 
products are likely to continue as crude oil production rises. 
It's, I think, worthwhile to point out that if refiners, by 
exporting surplus products, that is, in excess of what the U.S. 
demand is, it allows refiners to run at higher rates, and 
higher rates generally tend to mean that other products are 
being produced that consumers want and presumably at lower 
prices, to the extent that products enter the global 
marketplace, gasoline, diesel fuel, it would tend to limit 
global price increases. As I said earlier in my testimony, I 
believe that product prices in the U.S. are largely being set 
in the global markets. To the extent that the U.S. is 
contributing supply to the global markets, it is probably 
helping keep global prices lower than they would otherwise be.
    The Chairman. I think if it was cut and dried as you've 
described, Mr. Sieminski, motorists and people pulling up to 
these pumps where they feel they're getting clobbered would 
feel a lot better, and that's why, I think, there's a bit more 
to the story than your description.
    Let's go to Mr. Klesse.
    Mr. Klesse. OK, if we take gasoline first, sir, the U.S. 
imports gasoline into the East Coast and we're exporting out of 
the Gulf Coast, primarily to Latin America and going down to 
South America and Brazil. The U.S. is still a net importer of 
gasoline by a very small amount.
    On diesel fuel, we have a lot of excess capacity. The U.S. 
market is about 3.7 million barrels a day and the industry is 
exporting over 800,000 barrels a day. There is not U.S. demand 
for the diesel.
    Now, these products are being drawn away in the U.S. Gulf 
Coast spot market by higher prices offered by these countries. 
If you think about it, about half of the diesel fuel is going 
to South America; the other half is going to Europe, and they 
are paying the price because they actually have to pay freight 
on top of that to get the price.
    Where do I think they're going? I think it's imperative for 
the U.S. refining industry, with the outlook of U.S. demand, 
that we continue to export.
    The Chairman. Let us have your colleague, Mr. Khan, let's 
bring you into this.
    Mr. Khan. Mr. Chairman, we used to be a large exporter-
importer of gasoline and now we're approaching a net neutrality 
in gasoline imports and exports. Latin America demand continues 
to grow; the last 10 years, demand has grown by about 150,000 
barrels per day per year in Latin America, so a lot of the 
excess production that U.S. refiners produce is now being 
shipped to South America and to Europe.
    Taking these raw materials such as crude oil and 
manufacturing them into higher-value products such as gasoline 
and diesel, we think is good for the U.S. economy. It increases 
our relative import-export balance in the United States
    Higher prices in the U.S. are also resulting in new 
investment, so we do see some refineries investing in increased 
capacity to produce more fuels in places where we are seeing 
some shortages from time to time.
    The Chairman. Yes, I think that part of what I'm hearing 
are descriptions of activities that are good for refiners and I 
question whether it's good for consumers, and that's, I think, 
part of the debate.
    Let me go to you, Mr. Gilligan, on the question of crude 
prices and benchmarks. One of the other issues that was raised 
in the Congressional Research Service analysis that was done 
for us is that usual price benchmarks like West Texas 
Intermediate or Brent, one of the major international 
benchmarks, of course, don't accurately reflect the actual cost 
of crude oil to refiners; refiners are often paying less than 
the benchmark. In some cases, like in the Midwest and the 
Rockies, they have been paying a lot less. The European Union 
is reportedly investigating how oil producers may have been 
involved in manipulating these Brent oil prices. How do your 
members know whether or not they're paying a fair price for the 
products you buy if the benchmark doesn't reflect the actual 
cost of oil in the market?
    Mr. Gilligan. It's an excellent question and it sort of 
ties to some of the thoughts that I had in the earlier 
discussion. I think in some of your earlier comments, you're 
trying to make a nexus between gas prices and the prices 
refiners pay for crude; that's not the nexus that exists. The 
nexus as I see it is the nexus to the benchmark, WTI and Brent; 
that is, at least in the last 2 or 3 weeks, we've seen sizable 
increases in WTI and Brent, and those are what are showing up 
at the wholesale rack. So we know--refiners have to be 
competitive. Petroleum marketers, we have our computer screens 
and we look at all the terminals in the area and Valero has to 
make sure that their spot price is competitive with Exxon and 
with Chevron and their other competitors, so they're going to 
move to the lowest spot price, which then sort of affects all 
the other prices in the terminal. Those markets are fairly 
transparent, but I do think it's important to note that it's 
WTI and Brent that basically is what we believe drives prices, 
not so much the price that refiners pay for the product.
    The Chairman. Would any of you others like to add an 
additional point on the question of the benchmarks?
    Mr. Gilligan. I would go on to stress that that's why we 
continue to push for both European and United States--a good 
regulation of the futures markets, to make they're honest 
markets.
    The Chairman. Gentlemen, here's my take of where we are.
    The market in the oil business has changed and changed 
dramatically, and too often, and particularly when I asked you 
the questions early on, Mr. Sieminski, about why the lower cost 
of new oil supplies is not being passed on to the consumer, you 
gave me the answer that we have heard for years and years, and 
basically sort of defies what the industry has been saying, and 
what I'd like to do is find a way, and we're going to be 
following up with all of you, to work in a bipartisan way to 
come up with some practical approaches to try to help consumers 
who are still getting hammered. They're getting hammered today 
at the pump. You heard Senator Baldwin talking about it at a 
time when their newspapers are filled with stories about how 
there are new oil supplies and the consumer is saying, ``How is 
going to get to me?'' Mr. Sieminski, I've got to think that 
there is some affordable way in real-time to get people 
information about these refinery outages, and I'm going to work 
with you with respect to your budget, and suffice it to say, 
those of you in the industry, and following it, I hope you'll 
come forward with your ideas for changes that will reflect a 
very different marketplace because when you go through the 
charts that I've gone through today and the ones that we had 
prepared with the data from the Congressional Research 
analysis, we were pointing to hard information about record-
level refining margins--nobody's saying every bit of it's a 
profit; certainly, a significant part of it is, but there isn't 
any question that the lower crude oil costs from the new 
sources of production are not getting through, not getting 
through, to the consumer's wallet at the pump and that is why 
people are asking these questions that you've had today, and 
this will not be the last time we will be at it, and certainly, 
Mr. Klesse, you've made a number of good points. I note the 
fact that you all, also, report information about outages; 
we're going to be looking at the RINs issue; I have some real 
questions about whether the renewable fuel targets can be hit, 
so there are a number of questions here to look at. But I do 
want us to take steps that can help the consumer now with price 
spikes that are clearly working a hardship on working class 
people and small businesses and the consumer, and it's one of 
the things that Democrats and Republicans have said they want 
different about energy policy. It's always been the consumer's 
been an afterthought, and the consumer is no longer going to be 
an afterthought, and you've heard that from Democrats and 
Republicans.
    We'll keep the record open because a number of Senators 
would like to ask questions. We'll allow all of you to offer 
additional viewpoints.
    The Chairman. I thank you for your patience on a busy 
morning here in the Senate, and with that, the Energy and 
Natural Resources Committee is adjourned.
    [Whereupon, at 12:09 p.m., the hearing was adjourned.]
                               APPENDIXES

                              ----------                              


                               Appendix I

                   Responses to Additional Questions

                              ----------                              

    Responses of Chris Plaushin to Questions From Senator Murkowski
    Question 1. National Energy Policy--You mention the need for a 
national energy policy. In your view, what are the crucial features of 
a national energy policy that our nation lacks? What issues should an 
energy policy address that would be or are important to ensuring energy 
security?
    Answer. In short, AAA believes that all options need to be a part 
of any discussion in developing a national energy policy. The most 
important measurement to any such policy will be in its ability to 
provide stability for consumers. As we have seen throughout 2013 
consumers have been subject to extreme volatility in retail gas prices, 
not necessarily as a nation but in regional pockets. AAA charts the 
rise and fall of the national retail average but we also monitor the 
prices for metropolitan areas and regions around the country. We have 
observed the phenomenon of national prices drifting slowly lower as 
demand for fuel is down and inventories of refined product are 
plentiful but at the same time some pockets of the country-in 
particular the Midwest-are subjected to intense price spikes simply 
because they are a captive audience to refinery issue or other regional 
disruption. Policymakers should seek a national energy strategy that 
does not necessarily hold lower prices as its key benchmark but more 
stable, predictable prices with less fluctuations for consumers.
    Question 2. E15 Position--Please summarize AAA's views on E15 for 
the record of our hearing. Do you advise drivers to use this fuel? At 
present, how many vehicles have been warrantied to run on E15 by 
automakers?
    Answer. AAA believes that ethanol blended fuels have the potential 
to provide drivers with a welcome choice at the pump, which supports 
American jobs, promotes American energy independence and can save 
Americans money. In order to realize these benefits, it is imperative 
that increased ethanol blends-or any new fuels-are only brought to 
market when consumers have been clearly informed and protected. The 
introduction of E15 gasoline to consumers has failed to meet this 
obligation.
    We recommend that our members, as well as the public refer to the 
owner's manual to determine whether or not the manufacturer recommends 
the use of E15. Our automotive engineering experts have reviewed the 
available research and believe that sustained use of E15 in both newer 
and older vehicles could result in significant problems such as 
accelerated engine wear and failure, fuel-system damage and false 
``check engine'' lights for any vehicle not approved by its 
manufacturer to use E15. Automakers also advise they may void 
warranties for anyone using E15. Five manufacturers (BMW, Chrysler, 
Nissan, Toyota and Volkswagen) are on record saying their warranties 
will not cover fuel-related claims caused by the use of E15. Eight 
additional automakers (GM, Ford, Honda, Hyundai, Kia, Mazda, Mercedes-
Benz and Volvo) have stated that the use of E15 does not comply with 
the fuel requirements specified in their owner's manuals and may void 
warranty coverage.
       Response of Chris Plaushin to Question From Senator Risch
    Question 1. EPA's proposed percentage bio blending standard for 
gasoline and diesel combined is 9.63% for the year 2013. The Energy 
Information Administration (EIA) has told Congress that virtually all 
ethanol blending with gasoline is at the 10% level. However, EIA has 
also stated that biodiesel blending is RIN deficient. So if a refiner 
produces a higher percentage of diesel, there is no possible way to 
meet EPA's proposed standard unless they buy credits. These credits 
that used to cost pennies per RIN gallon now cost over a dollar with 
predictions that RINs will go over $3.00 in 2014.
    Please give us your thoughts on the unfairness and the unintended 
consequences of the Renewable Fuel Standard.
    Answer. Foremost to AAA is the potential impact or consequences of 
E15 on vehicles and. consumers. If EPA determines that the current RFS 
targets for conventional biofuels cannot be met without utilizing E15, 
AAA believes action should be taken to adjust the targets.
    Question 1a. What suggestions do you have for changes that will 
correct this problem?
    Answer. AAA would call on Congress to grant the EPA broader 
authority to reduce RFS targets for conventional biofuels and direct 
the agency to use this authority to adjust targets that are 
unachievable or risk severely impacting the prices motorists pay at the 
pump. A clearly communicated strategy sends a signal to both consumers 
and markets that Washington has protections in place to prevent 
unachievable targets and spiking prices for RINS from ultimately 
resulting in volatile pump prices for American motorists.
                                 ______
                                 
   Responses of William R. Klesse to Questions From Senator Murkowski
    Question 1. Number of Refineries in the U.S.--In your testimony you 
note that no new refinery has been built since the 1980s. In your view, 
is there a need for new refineries in the U.S.? What are the current 
obstacles to building new refineries?
    Answer. As you have noted from my testimony, no new refinery with 
significant operating capacity has been constructed since the 1980s. 
Indeed, the total number of refineries has decreased by half. At the 
same time, overall refinery capacity has increased from 16,859,000 
barrels-per-calendar-day then to 17,823,659 barrels-per-calendar-day 
with an annual utilization rate of about 89 percent today. As the 
number of U.S. refineries has declined, the operating capacity 
complexity of the remaining refineries has been increased to keep up 
with worldwide demand.
    Among the obstacles to building new refineries are declining 
gasoline demand and burdensome regulations. As was noted in the July 
16th hearing, U.S. refinery operations are among the most regulated in 
the country. At the same time, U.S. refineries are among the cleanest 
and most efficient in the world. A reasonable approach to regulation is 
one that both improves the environment while allowing the industry to 
remain competitive.
    Question 2. Refinery Outages--Please describe the decision-making 
process for planned outages, or turnarounds. What factors come into 
play? What do you do to help protect against supply interruptions? In 
what circumstances do unplanned outages occur? What can be done to 
limit supply interruptions?
    Answer. For environmental and safety reasons, it is necessary every 
few years to shut down an operating unit for a ``turnaround.'' 
Generally, turnarounds are scheduled for low-demand seasons with 
weather considered for efficient turnaround execution. We schedule 
turnarounds transparently so all appropriate parties can prepare and 
ensure that these events are executed quickly and efficiently with 
minimal market disruption. Supply arrangements are made to cover for 
lost production, and there is currently surplus refining capacity in 
the United States. Clearly, unforeseen problems can complicate even the 
best plans, resulting in localized supply concerns. As refineries have 
become larger, unplanned outages because of mechanical problems have 
caused increased priced volatility seen by the consumer.
    The bottom line is that refiners take measures to limit the effect 
of unit outages on inventory and supply. These include:

   Increased production of alternate units;
   Continued production from partially shut down units; import 
        of alternate supply; and
   stockpiling of inventory leading up to a turnaround or 
        outage.

    These steps are crucial to avoiding a major disruption in supply 
from a single outage. When there are regional shortages caused by 
hurricanes or other factors affecting refinery production, one area 
where regulators can help is by quickly providing Jones Act waivers 
that would increase the number of available ships, so that fuel 
supplies can quickly be moved from unaffected parts of the country.
    Question 3. Delayed RFS Rules--At the time of this hearing, EPA 
still had not finalized its 2013 RFS rule, for volume obligations, even 
though it is mid-July of the year in which that rule is meant to apply. 
What does this delay mean-not least in terms of certainty-for your 
company?
    Answer. As you are aware, Valero is an obligated party under the 
RFS. As such, we have to carefully plan a compliance strategy each year 
to ensure sufficient renewable identification numbers (RINs) are 
procured in the most efficient and effective manner possible. 
Accordingly, any delay or loss of certainty as to our upcoming 
obligations reduces our ability, and those of other obligated parties, 
to plan and implement an effective compliance strategy.
    More important than any delay, however, is what actions EPA 
actually takes to remedy the current market situation. As we have 
stated, we believe the current RFS program is broken and that Congress 
needs to develop new legislation that reflects actual market 
conditions, protects U.S. consumers, and actually produces 
environmental benefits. As this discussion takes place in Congress, EPA 
should immediately revisit the renewable volume obligations for both 
2013 and 2014. These totals should reflect the realities of the 
marketplace, including the downturn in gasoline demand and the existing 
levels of advanced biofuel production.
    Question 4. Obligated Parties Under the RFS--Your written testimony 
points out that the ``obligated parties'' under the RFS-mainly refiners 
and fuel importers-may make less sense today than when the RFS was 
originally established.
    a. Would it make more sense to designate fuel blenders as obligated 
parties?
    b. Would such a shift be sufficient or insufficient to resolve the 
larger, structural difficulties with the RFS?
    Answer. To be clear, it is our view that it is time to revisit the 
current implementation of the RFS to reflect the current oil supply 
picture and other changes in the market. For that reason, the current 
RFS should be repealed and new legislation developed. As your question 
points out, one of the problems with the structure of the RFS is the 
issue of refiners and importers-but not blenders being obligated 
parties. This produces an unlevel playing field that picks winners and 
losers within the same marketplace. This system has also been one of 
the main reasons underlying the current problems in the market for 
renewable identification numbers (RINs) which have gone from $0.05 in 
late 2012 to as high as $1.45 recently for corn ethanol.
    Placing the RFS obligation on fuel blenders would be one step to 
addressing the difficulties in the system by allowing the obligation to 
be placed where renewable fuel actually enters the transportation mix. 
This would be a welcome development and address part of the current 
problem but not the whole problem. The fact remains that the economy 
and the fuels market are not the same as they were in 2007. Congress 
and the Administration should amend the current program and develop a 
new system that is reflective of current conditions and protects 
consumers and small businesses.
    Question 5. E15--What are the various hurdles that E15 would need 
to overcome before it can be deployed and used by American motorists?
    Answer. While Valero supports ethanol and is a leading producer, 
experts have repeatedly noted that the E-15 blend is not warranted for 
use by 95 percent of cars on the road today. E-15 reduces engine life 
and prompts fuel pump failures and consumer misfuelings. The American 
Automobile Association (AAA) even called on EPA ``to suspend the sale 
of E-15 until motorists are better protected.'' There are also issues 
with boats, lawn mowers, motorcycles and other small engines. Put 
simply, E15 has not been demonstrated to be compatible with all 
gasoline-powered engines. By acting without adequate scientific 
evidence to approve the use of E15, EPA has created safety and 
liability concerns regarding the operation of the vehicles and outdoor 
power equipment used by hundreds of millions of Americans every day.
    Defending its actions while recognizing the real-life consequence, 
EPA stated that they would devise a program that would prevent 
misfueling of E15 with incompatible engines. However, perhaps the 
strongest indictment of EPA's certification of E15 for any engine type 
came from the automakers in a response to a question from Congress in 
2011. Without exception, the auto manufacturers responded that use of 
E15, even in their newest vehicles, would damage engines, void 
warranties and reduce fuel efficiencies. Very simply, we believe the 
government should not be promoting a fuel to consumers unit these 
safety and reliability issues are addressed. The simplest and safest 
solution is to refine the RFS to avoid the so-called blend wall.
    Question 6. The ``Regulatory Swamp''--In your testimony, you 
describe the regulations being issued by EPA as a ``regulatory swamp.'' 
Could you describe in greater detail what the refining industry is 
facing right now, and what the cumulative consequences of those 
regulations could be?
    Answer. Refinery operations are subject to extensive environmental 
regulations. Refiners are among the most regulated industry in the 
country, and U.S. refineries are already among the cleanest and most 
efficient in the world. A reasonable approach to regulation is one that 
both improves the environment while allowing the industry to remain 
competitive. A host of recent actions by EPA, referred to as the 
``regulatory swamp'' due to the close proximity of their compliance 
targets and high costs, with very limited benefits, will create a 
highly unpredictable regulatory environment for our industry and 
contribute to a climate where no new refineries come online and those 
that do exist will struggle to stay online. These actions include:

   Proposed Tier 3 Gasoline and Diesel Standards
   Greenhouse Gas Rules and Permitting
   Finalized National Ambient Air Quality Standards (NAAQS) for 
        Particulate Matter
   Finalized Mercury Air Toxics Rule
   Finalized Emission Standards for Boilers
   Final New Source Performance Standards (NSPS) for Oil and 
        Gas Production
   Finalized Greenhouse Gas Standards for Cars and Light Trucks
   Final National Emissions Standards for Hazardous Air 
        Pollutants at Petroleum refineries

    Valero has estimated that its costs alone for compliance with the 
Proposed Tier 3 standards will be between $300 million and $400 million 
and will raise the cost of manufacturing gasoline a couple of cents per 
gallon. It will also increase our greenhouse gas emissions because of 
the additional processing.
    In addition to EPA, other regulatory agencies and states have 
pursued independent regulations. For example, California's Low Carbon 
Fuel Standard (LCFS) and statewide cap-and-trade program were issued as 
part of the state's Global Warming Solutions Act. The LCFS in 
particular does little to achieve environmental objectives while 
discriminating against crude sources to the detriment of California 
consumers. These rules pick winners and losers among the refining 
industry in place of letting market forces operate as impacts reflect 
the individual refinery configurations and your access to specific 
crude oils.
    As these regulations increase capital expenditures, and 
subsequently raise costs of operations they continue to pressure the 
economic sustainability of refinery operations, which under the current 
low margin environment can increase the risk of refinery closures and 
consequential job and economic loss. Overall, the regulations tend to 
create unintended consequences that duly disadvantage the US domestic 
refining industry relative to other refining centers of the world. The 
risks of this imply that companies could thus move operations to other 
countries with less stringent controls, increasing domestic 
manufacturing shutdowns, with implicit employment and tax revenue loss 
as opportunities are created overseas.
    This is not just a hypothetical. A 2011 report by the Department of 
Energy found that the cumulative burden of federal regulations was a 
significant factor in the closure of 66 domestic petroleum refineries 
from 1990 to 2010. In addition to increasing the cost of gasoline, 
additional regulations ``may lead to additional job losses for America, 
weaken the U.S. economy, make America more reliant on nations in 
unstable parts of the world for vital fuels and petrochemicals, and 
ultimately endanger our national security.''
    Question 7. Importance of Keystone XL--In your testimony, you note 
that ``Valero supports construction of the Keystone XL pipeline . . . 
'' Could you expand on its significance to your company, first-and then 
to our economy and energy security?
    Answer. Valero supports construction of the Keystone XL Pipeline 
and believes it will be in the strong energy security and economic 
interest of the U.S. and will bring a specific quality of crude suited 
for many U.S. Gulf Coast refineries to the Gulf Coast market. Valero, 
as with all independent refiners, buys all of the oil we process. If 
projects like the Keystone XL Pipeline can make North American produced 
oil available to our refineries, Valero and other refiners can 
increasingly rely upon increased North American oil which has the 
potential to lower prices for consumers. Increased availability of 
North American oil also means that we won't have to buy more oil from 
other sources outside the U.S. and Canada. This increases the Nation's 
energy security and also reduces the need for long-range shipping that 
increases both costs and greenhouse gas emissions.
    Question 8. Impact of Increased Domestic Production-You described 
the importance of increased domestic production on the outlook for 
refiners in the U.S. Without this new production, what do you think the 
refining industry would look like today?
    Answer. The outlook for refiners has improved significantly due to 
the increase in North American natural gas and crude oil production 
which are giving the industry competitive advantages in the global 
market. Valero in particular has sought to benefit from the revolution 
resulting from increased domestic shale gas and oil production. 
Refining is energy intensive, and Valero consumes about 700 million 
cubic feet a day of natural gas. In fact, energy is the largest 
component of a refinery's variable operation costs. Additionally, 
natural gas liquids are an important ingredient in creating finished 
products from crude oil, and the current supply dynamics have reduced 
the costs of these feedstocks. As shale oil production has increased, 
larger volumes of crude oil from highly productive basins like the 
Bakken and Eagle Ford have replaced imports for the domestic refining 
industry.
    Like many major domestic manufacturing industries, the refining 
sector is energy intensive. In addition to lower operating costs from 
lower-priced natural gas, the availability of vast new supplies of 
crude oil to refineries on the U.S. coasts has made these plants more 
competitive. This increase in competitiveness and profitability in the 
refining sector ultimately benefits consumers in the form of lower 
gasoline and diesel prices. To jeopardize this development with 
burdensome one-size-fits-all federal regulations would be foolhardy and 
harmful to America's economy and American workers.
      Response of William R. Klesse to Question From Senator Udall
    Question 1. As many of my colleagues here on the committee have 
heard me say again and again, I believe that Colorado is truly a model 
for the United States in its pursuit of a balanced approach to domestic 
energy development. As we work toward achieving true energy self-
reliance through expanded domestic oil development, it is important 
that we do so in a manner that is safe and responsible. So my question 
for the industry is: as oil and gas exploration, production and 
refining continues to expand in the United States, what is the industry 
doing to develop new methods and technologies to ensure that our air 
remains clean, our water is fresh and our communities are safe?
    Answer. Valero also believes in a balanced approach to energy 
policy in the United States. While we have discussed the critical role 
the company plays in U.S. energy security, we take our environmental 
obligations equally as seriously. Since 1990, the refining industry as 
a whole has spent over $128 billion on environmental improvements. 
Though the industry has greatly expanded during this time, 
environmental emissions have decreased over the last 20 years. This 
decrease in emissions comes despite increasingly stringent refined 
product specifications, and an overall increase in refinery production 
of gasoline and jet and diesel fuels. Processing heavier and sour crude 
that have been available to the market has required more processing. 
Petroleum refining is an energy intensive industrial process, but the 
industry has made record improvements to lessen its environmental 
footprint. Environmental stewardship is a core value at Valero. As an 
example, we have spent approximately $525 million to build a state-of-
the-art flue-gas scrubber, one of the world's largest, at our Benicia 
refinery in California. This expenditure reduced sulfur dioxide 
emissions by 95 percent and nitrogen oxide emissions by percent.
    Valero has also spent $2.6 billion at its refineries on 
environmental upgrades that further reduced emissions during the last 
six years. Under a comprehensive Energy Stewardship Program, Valero 
refineries reduced energy consumption per barrel of throughput by 12% 
between 2008 and 2012 which has reduced our greenhouse gas emissions. 
The refining industry is constantly adapting to changing times and is 
leading the way in the development of renewable fuels, and Valero is 
playing an active role in this innovation. Valero acquired 10 state-of-
the-art ethanol plants, which operate under our subsidiary Valero 
Renewable Fuels Company, LLC, making Valero the first traditional 
refiner to enter the ethanol production market in a significant way. 
Also, Diamond Alternative Energy LLC, a Valero subsidiary, produces 
renewable diesel fuel from recycled animal fat and used cooking oil in 
partnership with Darling International Inc. at a 10,000-barrel-per-day 
unit at the St. Charles Refinery in Louisiana that just became 
operational.
    Valero's environmental efforts have consistently been recognized. 
In 2013 Valero's McKee Refinery received the Texas Environmental 
Excellence Award for the company's wind farm that reduces reliance on 
conventional power sources. Additionally, Valero's St. Charles Refinery 
was recognized by the Louisiana Department of Environmental Quality and 
the Louisiana Chapter of the Air and Waste Management Association for 
its catalytic cracker conversion project that reduced overall facility 
air emissions and eliminated thousands of tons of waste catalyst 
generated annually.
   Responses of William R. Klesse to Questions From Senator Barrasso
    Question 1. The spot prices for certain Renewable Identification 
Numbers (RINs) recently reached an all-time high. Under the Renewable 
Fuel Standard (RFS), refiners must obtain RINs to verify the amount of 
biofuels blended into gasoline and diesel. Since January 1, 2013, the 
spot prices for RINs have increased over 1500 percent. You testified 
that ``the RINs market has . . . resulted in increased compliance 
costs. most of which are passed on to consumers.'' Would you expand 
upon how the RFS impacts the price of gasoline and diesel?
    Answer. As the Committee is well aware, obligated parties under the 
RFS, refiners and importers, but not blenders, are required to 
demonstrate compliance with their renewable volume obligation (RVO) 
through the submission of renewable identification numbers (RINs). 
Unfortunately, the RINs market has caused significant unintended 
consequences. With the original 2005 law and its volumes, RINs were 
necessary for flexibility and the ability to track the program. When 
the law was revised in 2007 and the renewable volumes greatly 
increased, combined now with much lower than expected gasoline demand, 
RINs have become a huge cost and fairness issue. Also, in the past two 
years, the RINs market has been beset by allegations of fraud that has 
questioned the Environmental Protection Agency's (EPA) ability to 
administer the RFS program and resulted in increased compliance costs 
for obligated parties-most of which are passed on to consumers.
    Most importantly, as U.S. gasoline demand declined from 2007 and as 
the renewable fuels mandate volumes increase, some U.S. refiners-those 
that are large merchants and wholesale, spot sellers-find themselves in 
an unintended predicament of either reducing gasoline production, 
exporting more gasoline at discounted prices, or buying RINs, which 
soon may not even be available because the market is going infeasible.
    At Valero alone, we anticipate cost increases of some $600 to $800 
million this year just as a result of volatility in the market for 
RINs. Unfortunately, this cost will not add one more gallon of fuel 
into the market. It is nothing more than a federally mandated cost to 
each gallon of transportation fuel that may be passed on to the 
consumer.
    At the outset of the RFS, EPA found in its regulatory preamble that 
RIN's cost would be negligible. This estimate has turned out to be 
profoundly incorrect as the program approaches an infeasible situation, 
expected in 2014.
    Question 2. You testified that ``some U.S. refiners.find themselves 
in an unintended predicament of either reducing gasoline production, 
exporting more gasoline at discount prices, or buying renewable fuel 
credits (RINs), which soon may not even be available because the market 
is going infeasible.'' Would you explain how the RFS encourages 
refiners to produce less gasoline or export gasoline at discounted 
prices?
    Answer. As U.S. gasoline demand declined from 2007 and as the 
renewable fuels mandate volumes increase, some U.S. refiners-those that 
are large merchants and wholesale, spot sellers-find themselves in an 
unintended predicament of either reducing gasoline production, 
exporting more gasoline at discounted prices, or buying renewable fuel 
credits (RINs), which soon may not even be available because the market 
is going infeasible. If the option of buying RINs doesn't exist because 
none are available or because of very high pricing, the domestic supply 
will be reduced. It's hard to believe that when Congress passed the 
Energy Independence and Security Act of 2007, a possible outcome was to 
reduce U.S. gasoline supplies and increase gasoline prices. However, as 
a refiner and an ethanol producer, that is exactly the potential 
outcome we find ourselves in today. No one expects that U.S. gasoline 
demand will rebound strongly and to begin to grow again, and there are 
physical constraints on using higher blends of ethanol in gasoline 
including the lack of car warranties to approve those blends. As a 
result, there simply aren't enough gallons of gasoline in which to put 
all of the required gallons of ethanol-and that has driven the price of 
corn ethanol RINs from $0.05 in late 2012 to as high as $1.16 recently. 
Also, there is no cellulosic ethanol and advanced ethanol has to be 
imported.
    Question 3. You testified that EPA is in the process of imposing a 
number of new regulations on American refineries. These include EPA's 
proposed ``Tier 3'' gasoline and diesel regulations. You explain that 
EPA's Tier 3 regulations alone will cost Valero between $300 million 
and $400 million and will raise the cost of manufacturing gasoline a 
couple of cents per gallon. You also cite a Wood Mackenzie report which 
states that EPA's regulations may ``increase the risk of refinery 
closures and consequential job and economic loss.'' Would you discuss 
in greater detail the impact that EPA's regulations are having on 
American refineries and consumers?
    Answer. Refinery operations are subject to extensive environmental 
regulations. Refiners are among the most regulated industry in the 
country, and U.S. refineries are already among the cleanest and most 
efficient in the world. A reasonable approach to regulation is one that 
both improves the environment while allowing the industry to remain 
competitive. A host of recent actions by EPA, referred to as the 
``regulatory swamp'' due to the close proximity of their compliance 
targets and high costs, with very limited benefits, will create a 
highly unpredictable regulatory environment for our industry and 
contribute to a climate where no new refineries come online and those 
that do exist will struggle to stay online. These actions include:

   Proposed Tier 3 Gasoline and Diesel Standards
   Greenhouse Gas Rules and Permitting
   Finalized National Ambient Air Quality Standards (NAAQS) for 
        Particulate Matter
   Finalized Mercury Air Toxics Rule
   Finalized Emission Standards for Boilers
   Final New Source Performance Standards (NSPS) for Oil and 
        Gas Production
   Finalized Greenhouse Gas Standards for Cars and Light Trucks
   Final National Emissions Standards for Hazardous Air 
        Pollutants at Petroleum refineries

    Valero has estimated that its costs alone for compliance with the 
Proposed Tier 3 standards will be between $300 million and $400 million 
and will raise the cost of manufacturing gasoline a couple of cents per 
gallon. It will also increase our greenhouse gas emissions because of 
the additional processing.
    In addition to EPA, other regulatory agencies and states have 
pursued independent regulations. For example, California's Low Carbon 
Fuel Standard (LCFS) and statewide cap-and-trade program were issued as 
part of the state's Global Warming Solutions Act. The LCFS in 
particular does little to achieve environmental objectives while 
discriminating against crude sources to the detriment of California 
consumers. These rules pick winners and losers among the refining 
industry in place of letting market forces operate as impacts reflect 
the individual refinery configurations and your access to specific 
crude oils.
    As these regulations increase capital expenditures, and 
subsequently raise costs of operations they continue to pressure the 
economic sustainability of refinery operations, which under the current 
low margin environment can increase the risk of refinery closures and 
consequential job and economic loss. Overall, the regulations tend to 
create unintended consequences that duly disadvantage the US domestic 
refining industry relative to other refining centers of the world. The 
risks of this imply that companies could move operations to other 
countries with less stringent controls, increasing domestic 
manufacturing shutdowns, with implicit employment and tax revenue loss 
as opportunities are created overseas.
    This is not just a hypothetical. A 2011 report by the Department of 
Energy found that the cumulative burden of federal regulations was a 
significant factor in the closure of 66 domestic petroleum refineries 
from 1990 to 2010. In addition to increasing the cost of gasoline, 
additional regulations ``may lead to additional job losses for America, 
weaken the U.S. economy, make America more reliant on nations in 
unstable parts of the world for vital fuels and petrochemicals, and 
ultimately endanger our national security.''
    Question 4. You testified that ``unfettered exports of natural gas 
. . . may have significant unintended consequences and will raise 
costs.'' You also state that ``[p]olicies that are too restrictive 
towards gasoline exports could undermine or even close marginally 
profitable refineries.'' You go on to say that ``[t]he U.S. refining 
industry is a very efficient, but as all manufacturing, is faced with 
high labor and regulatory costs. Low priced natural gas offsets these 
costs and keeps us competitive.'' (emphasis added).
    Other manufacturers and industries face high labor and regulatory 
costs. If the Federal government should limit natural gas exports to 
offset the refining industry's labor and regulatory costs and keep the 
refining industry competitive, why shouldn't the Federal government 
limit exports of refined petroleum products to help other manufacturers 
or industries offset their labor and regulatory costs and keep these 
manufacturers and industries competitive?
    Answer. Valero is a firm participant in the international 
marketplace for robust trade in energy commodities. Valero seeks lower-
cost and reliable inputs for our refineries, whether from within the 
United States or from foreign sources. Given recent developments in 
shale plays, we have frankly benefited from new secure domestic 
supplies of crude oil and natural gas. Valero then takes those inputs 
and through the application of American capital, technological know-
how, and expert workforce, we transform oil and gas into a broad array 
of fuels that satisfy domestic and international demands. We believe 
there is a fundamental difference between manufactured products of the 
sort refiners make and the raw material inputs into that manufacturing 
process. Indeed, every multiple Administrations for each party over the 
last five decades have found that a robust domestic refining sector is 
critical for national security. That said, Valero is not calling for a 
prohibition on natural gas exports. We merely raise the question of 
whether or not the public interest test already present in current law 
contemplated unfettered exports without respect to the competitiveness 
of domestic assets.
      Response of William R. Klesse to Question From Senator Risch
    Question 1. EPA's proposed percentage bio blending standard for 
gasoline and diesel combined is 9.63% for the year 2013. The Energy 
Information Administration (EIA) has told Congress that virtually all 
ethanol blending with gasoline is at the 10% level. However, EIA has 
also stated that biodiesel blending is RIN deficient. So if a refiner 
produces a higher percentage of diesel, there is no possible way to 
meet EPA's proposed standard unless they buy credits. These credits 
that used to cost pennies per RIN gallon now cost over a dollar with 
predictions that RINs will go over $3.00 in 2014.
    a) Please give us your thoughts on the unfairness and the 
unintended consequences of the Renewable Fuel Standard.
    Answer. As the Committee is well aware, obligated parties under the 
RFS, refiners and importers, but not blenders, are required to 
demonstrate compliance with their renewable volume obligation (RVO) 
through the submission of renewable identification numbers (RINs). 
Unfortunately, the RINs market has caused significant unintended 
consequences. With the original 2005 law and its volumes, RINs were 
necessary for flexibility and the ability to track the program. When 
the RFS was revised in 2007 and the renewable volumes greatly 
increased, combined now with much lower than expected gasoline demand, 
RINs have become a huge cost and fairness issue.
    Most importantly, as U.S. gasoline demand declined from 2007 and as 
the renewable fuels mandate volumes increase, some U.S. refiners- those 
that are large merchants and wholesale, spot sellers-find themselves in 
an unintended predicament of either reducing gasoline production, 
exporting more gasoline at discounted prices, or buying RINs, which 
soon may not even be available because the market is going infeasible. 
If the option of buying RINs doesn't exist because none are available 
or because of very high pricing, the domestic supply will be reduced. 
It's hard to believe that when Congress passed the Energy Independence 
and Security Act of 2007, a possible outcome was to reduce U.S. 
gasoline supplies and increase gasoline prices. However, as a refiner 
and an ethanol producer, that is exactly the potential outcome we find 
ourselves in today. No one expects that U.S. gasoline demand will 
rebound strongly and to begin to grow again, and there are physical 
constraints on using higher blends of ethanol in gasoline including the 
lack of car warranties to approve those blends. As a result, there 
simply aren't enough gallons of gasoline in which to put all of the 
required gallons of ethanol-and that has driven the price of corn 
ethanol RINs from $0.05 in late 2012 to as high as $1.45 recently. 
Also, there is no cellulosic ethanol and advanced ethanol has to be 
imported.
    At Valero alone, we anticipate cost increases of some $600 to $800 
million this year just as a result of volatility in the market for 
RINs. Unfortunately, this cost will not add one more gallon of fuel 
into the market. It is nothing more than a federally mandated cost to 
each gallon of transportation fuel that may be passed on to the 
consumer.
    b) What suggestions do you have for changes that will correct this 
problem?
    Answer. No matter what one's view on ethanol and other alternative 
fuels is, it is time to revisit the current implementation of the RFS 
in order to allow the orderly movement of renewable fuels into the fuel 
supply in a responsible manner that protects consumers and small 
businesses. The oil supply picture has changed, the basis of the 
original legislation has changed, the RFS should be repealed and new 
legislation developed.
    As the process of developing new legislation moves forward, the 
Administration can take immediate steps to stem the impacts of the 
current system on U.S. consumers and small businesses. Without waiting 
for Congress, the Administration can adjust the renewable fuel volume 
requirements for 2013 and send a signal to the market as to its intent 
to do the same in 2014. The Administration can also ask for public 
comment on structural changes such as: designating fuel blenders as the 
obligated party in the RFS, establishing a "safety valve" that would 
freeze RIN prices at a certain point to prevent real harm to the 
economy, etc. These interim measures can buffer some of the current 
fears in the market as the Congress considers an appropriate mechanism 
to replace the current, and broken, RFS program.
                                 ______
                                 
     Responses of Dan Gilligan to Questions From Senator Murkowski
    Question 1. Energy Policy Initiatives--In your opinion, what policy 
initiatives are most important for Congress to pursue to help ensure 
affordable energy prices here in the U.S., including gasoline prices?
    Answer. It remains important for the U.S. to adopt policies that 
will reduce our dependence on foreign oil. While increased domestic oil 
production might not lead to lower prices at the pump immediately, this 
doesn't take away from the fact that the U.S. must continue to pursue 
domestic oil production on both public and private lands to prevent 
future oil price shocks and oil price volatility, and to curtail OPEC's 
market share of the world oil market.
    Congress must also expedite approvals for deep water drilling 
projects, approve the Keystone XL Pipeline, and delay EPA rules 
implementing Tier 3 gasoline requirements and new ozone standards. If 
EPA were to finalize rules requiring Tier 3 gasoline and new ozone 
standards, the rules would force much of the country into non-
attainment status which would require refineries to make a lower Reid 
Vapor Pressure (RVP) fuel and, in many cases, reformulated gasoline 
(RFG), and both would dramatically increase prices at the pump.
    Additionally, PMAA supports efforts to expand gas-to-liquids (GTL) 
technology which is a process that converts natural gas into clean, 
reliable diesel fuel. It was developed in the early 1920s and the 
diesel fuel produced can be used in the existing $500 billion 
downstream motor fuels distribution system without any costly upgrades. 
Furthermore, propane already has a distribution system that would cost 
much less to expand than to basically start from scratch with a CNG 
infrastructure system. Propane is a safe consumer and employee friendly 
product that is easy to work with once store personnel are properly 
trained. In addition, the cost of installing a propane fueling site 
runs about $20,000-$25,000 versus CNG at a cost of $750,000-$1 million 
per site. Propane mileage is similar to a vehicle running on E-10 
gasoline blend. Congress should enable innovation by promoting all fuel 
options, especially propane, given how closely it resembles CNG and LNG 
in fuel quality and CO2 emissions, and because of its cost-
effective motor fuels distribution system.
    Question 2. E15/E85-How much does it cost, on average, for a 
station owner to upgrade his or her infrastructure to accommodate the 
sale of E15? How about E85?
    Answer. To upgrade/retrofit a UST system to sell E10 plus blends, 
it will cost well beyond the means of an average convenience store 
owner. PMAA estimates that the average cost to retrofit a retail 
gasoline station with E15 compliant equipment to be between $375,000 
and $425,000 per site. Replacement of piping alone would cost at a 
minimum $150,000. Such compliance costs would be staggering for 
retailers and would undoubtedly force many, particularly in those rural 
areas to close down. Those who could afford a system retrofit would be 
forced to pass the cost along to customers in the form of significantly 
higher gasoline prices. E85 costs would be the same since anything 
above E10 has to be Underwriters Laboratories (UL) certified and most 
E10 plus UL certified equipment handles both E15 and E85 blends.
    Question 3. E15--What are the various hurdles that E15 would need 
to overcome before it can be deployed and used by American motorists?
    Answer. Currently, gasoline retail infrastructure equipment is 
certified to dispense and store up to 10 percent ethanol by UL. 
Although UL has expressed ``confidence'' that most retailers can safely 
sell up to 15 percent ethanol blended gasoline, they have not actually 
``certified'' existing dispensers, piping or underground storage tanks 
for such use. This is a major obstacle because several federal 
regulations, state laws, local ordinances and insurance policies 
require UL certified equipment.
    Retailers who decide to sell E15 could be held liable to pay for 
cleanup costs if a leak occurs due to the increased ethanol blends, and 
insurance companies may deny coverage. During the decision to waive 
portions of the Clean Air Act to allow the use of E15, little 
consideration was given to the issue of compatibility with existing UST 
legacy equipment. Statutory jurisdictional considerations 
notwithstanding, the fact remains that E15 will not be placed in 
widespread use in the short term until outstanding issues involving 
equipment compatibility are addressed.
    Additionally, auto manufacturers extend warranties on existing 
vehicle fleets up to 10 percent ethanol. Most are unwilling to amend 
their warranties to handle blends above 10 percent because tests have 
shown E15 could damage engines, fuel pumps and other system components. 
This position did not change after EPA approved E15 for 2001 and newer 
vehicles. PMAA is also concerned that if an owner of a pre-2001 vehicle 
misfuels with E15, the retailer would be held liable for damage to 
engine and emission system components. Appropriately labeled dispensers 
warning consumers not to dispense E15 into older vehicles will do 
little to reduce the risk of liability for the retailer.
    It is unlikely E85 would satisfy RFS corn-based ethanol blending 
requirements. E85 is still considered a niche market and many PMAA 
member companies have yet to offer E85 since there isn't enough E85 
compatible vehicles on the road to make a modest return on investment. 
Furthermore, E85 must be priced lower than conventional gasoline for 
motorists to receive similar energy content at a competitive price 
given that ethanol has a lower BTU energy content compared to 
conventional gasoline.
    Additionally, it's worth noting that existing E85 stations in the 
U.S. were permitted with a waiver from local authorities having 
jurisdiction (AHJ) (local fire marshals). The waivers tell the retailer 
that local fire marshals won't enforce compatibility standards against 
them for selling E85. However, the waiver still doesn't satisfy OSHA 
requirements. To date, very few E85 dispensers, hoses, nozzles, 
swivels, breakaways, shear valves, and submersible turbine pumps have 
been UL certified to handle E85. Both Gilbarco and Dresser Wayne have 
certified dispensers for E25.
    Question 4. E15 Sales--To the best of your knowledge, how many 
stations around the country are currently sellingE15? What are some of 
the roadblocks to its wider deployment?
    Answer. There only about two dozen stations are selling E15 fuel. 
As discussed above, several regulatory roadblocks still exist. PMAA 
believes the biggest E15 setback is lack of UL certification for legacy 
equipment and general liability regarding misfueling concerns.
    Question 5. Waivers--Your testimony briefly discusses the potential 
benefit of waivers-from the Renewable Fuel Standard, from reformulated 
gasoline requirements, and other regulations-in the event of regional 
natural disasters. Historically, have these waivers been granted on a 
timely basis?
    Answer. Historically, waivers haven't been granted in a timely 
fashion by the federal government. When Superstorm Sandy hit the 
Northeast, waivers such as hours-of-service (HOS), regional 
reformulated gasoline (RFG) and RFS waivers were granted, but well 
after the storm hit. Additionally, regional weight limit waivers, fuel 
specification waivers, and IRS fuel tax regulations specific to dyed 
(taxed)/undyed products (non-taxed) impacted the petroleum supply 
chain. PMAA is currently working with industry and the Obama 
Administration in speeding up this process to move product during 
emergencies. The Obama Administration and future Administrations need 
to waive fuel requirements well in advance of a storm in order to 
smoothly transport refined petroleum products to an affected region.
    Question 6. Refinery Outages--In your testimony, you state that 
PMAA supports funding for Section 804 of the 2007 energy bill, which 
authorized EIA to collect information about refinery outages. To be 
clear, is it fair to conclude that PMAA supports better communication, 
but not government control over those outages?
    Answer. That's correct. PMAA supports better communication between 
suppliers, petroleum marketers and government officials, but not 
government control over planned refinery outages. If the federal 
government could provide planned refinery outage information well in 
advance to refining companies, PMAA believes it could prevent multiple 
refinery locations from temporary suspending operations simultaneously, 
and therefore, prevent supply shocks and higher prices. Refiners can't 
communicate due to anti-trust laws, so they're unable to know when and 
where a refinery might have a planned refinery outage.
    Question 7. Retail Facilities--In your written testimony, you 
describe the new face of the retail gasoline industry over the past 10-
15 years as having moved from gas station ownership by major integrated 
oil companies to ownership primarily by small, independent businesses.
    a. What impact, if any, has this changed business model had on 
gasoline prices at the pump?
    b. How will this dynamic affect the potential deployment of E15 and 
E85?
    Answer. The price of oil and refined petroleum products are set in 
the global futures market exchanges (e.g., the Intercontinental 
Exchange and the Chicago Mercantile Exchange). Speculators and hedgers 
make bets or guesses on where they believe the oil market is headed 
depending on geopolitical events, the value of the U.S. dollar, market 
sentiment and supply and demand. Additionally, U.S. publically traded 
oil companies only control three percent of the world's oil proven 
reserves; therefore, their impact on the price of oil is limited.
    RFS obligated parties (refiners and importers) are required to 
blend a certain amount of ethanol into gasoline also known as renewable 
volume obligations (RVOs). Some refiners such as Valero have invested 
in ethanol facilities and can produce additional RVOs to sell in the 
market to other obligated parties who fall short. Thus, the tradable 
RINs market serves as an incentive for refiners to meet their volume 
obligations. However, the high cost of RINs is due to refiners hitting 
the maximum achievable amount that can work with legacy vehicles and 
motor fuels dispensing systems (aka E10 blendwall). Therefore, refiners 
have limited ability to impact the potential deployment of E15 and E85. 
If E15 were to be ``mandated by the market'' as upstream suppliers 
struggling to meet escalating RVOs, PMAA member companies couldn't 
supply E15 to non-compatible UST systems and pre-2001 vehicles. Given 
equipment compatibility issues have not been resolved, it could force a 
system wide retrofit of UST systems that would impose impossibly high 
compliance costs on retail marketers and could disrupt supply and 
result in sharp price increases for gasoline at the pump.
        Response of Dan Gilligan to Question From Senator Udall
    Question 1. With $4 per gallon gas becoming the norm, the state of 
Colorado has introduced policies that make it easier for Coloradans to 
purchase vehicles that run on alternative and more affordable sources 
of fuel. Do you see increased use of alternative consumer vehicles, 
like electric vehicles or natural gas vehicles, affecting gasoline 
prices over the next decade? What is the petroleum industry doing to 
prepare for these changes in market demands?
    Answer. First, PMAA doesn't support federal subsidies for CNG and 
LNG. Current natural gas prices have allowed for greater investment in 
natural gas infrastructure especially at truck stops. Second, we are 
not of the opinion that alternative fuel vehicles are going to be a 
significant portion of the overall vehicle mix through 2050. CNG and 
electric vehicles are at a premium over traditional fuel vehicles and 
with the sparseness of fueling facilities, and given the significant 
infrastructure costs of CNG compressor stations, it will be a long time 
before any viable impact will be realized.
    Natural gas will certainly impact diesel markets as fleets convert 
to LNG and refueling facilities for trucks grow. LNG for big trucks is 
cost effective today, but not currently suitable for light trucks and 
cars in the near future. Infrastructure costs are very high and fuel 
tank limits on cars are a big problem for CNG. The newly finalized CAFE 
standards will ultimately reduce demand; however, reduced demand does 
not always translate into lower prices at the pump. Global crude oil 
prices are the primary driver of gasoline prices and global demand for 
crude will likely continue to grow.
    If anything, as natural gas moves out of the regulated environment 
into an unregulated motor fuels market and with exports of LNG ramping 
up to serve the MCF Japanese and European markets, CNG/LNG will begin 
experiencing price parity with traditional fuels. At that point, the 
life cycle return for the significant differentiation in conversion and 
new vehicle cost will not be warranted. Electric vehicles currently 
enjoy tax and incentive benefits but that too will play out. As power 
plants switch from coal to natural gas, prices will also go up. In the 
9-county Front Range area, prices over the next 10 years are 
anticipated to increase 30 percent due to the legislature encouraging 
natural gas conversion from coal. CNG is costing some marketers as much 
as $.75 per gallon to pump due to the peak demand charges for 
electricity experiencing new record highs.
        Response of Dan Gilligan to Question From Senator Risch
    Question 1. EPA's proposed percentage bio blending standard for 
gasoline and diesel combined is 9.63% for the year 2013. The Energy 
Information Administration (EIA) has told Congress that virtually all 
ethanol blending with gasoline is at the 10% level. However, EIA has 
also stated that biodiesel blending is RIN deficient. So if a refiner 
produces a higher percentage of diesel, there is no possible way to 
meet EPA's proposed standard unless they buy credits. These credits 
that used to cost pennies per RIN gallon now cost over a dollar with 
predictions that RINs will go over $3.00 in 2014.
    a) Please give us your thoughts on the unfairness and the 
unintended consequences of the Renewable Fuel Standard.
    Answer. The reason why ethanol RIN values have increased 
dramatically is due to refiners hitting the maximum achievable blending 
threshold allowed in the marketplace (E10). If EPA finalizes 2013 and 
2014 RFS ethanol blending volumes that force refiners to blend above an 
E10 blend, refiners are likely to cut gasoline production, export it or 
buy even more expensive ethanol RINs which will cause chaos in the 
retail motor fuels market place. Furthermore, no one anticipated that 
gasoline consumption would fall dramatically after 2007 which has only 
moved the ethanol blend wall closer. Given that small business 
petroleum marketers own and operate approximately 60 percent of all 
retail gasoline stations nationwide, it's important that they be 
included in the RFS negotiations this spring and summer.
    PMAA is currently concerned about the corn-based ethanol mandate 
given our concerns with misfueling and UST compatibility concerns, but 
have no position on the biodiesel mandate.
    b) What suggestions do you have for changes that will correct this 
problem?
    Answer. On May 16, 2013, PMAA's Board of Directors voted to support 
a regulatory fix to the RFS by urging the EPA Administrator to prevent 
chaos in the retail motor fuels marketplace by adjusting the corn-based 
ethanol mandate to a level achievable with E10 and reasonable growth 
for E85. The PMAA Board believes E15 has too many infrastructure, 
liability and marketplace issues to significantly expand national 
ethanol blending volumes in the short run. PMAA does not oppose E15 but 
has advised marketers to obtain knowledgeable legal and regulatory 
counsel before offering E15 at wholesale or retail.
                                 ______
                                 
    Responses of Jeffrey B. Hume to Questions From Senator Murkowski
    Question 1. Domestic Production--I appreciate your comments about 
technological developments providing access to a sustainable source of 
energy in the U.S., meaning oil and gas resources. Can you please 
expand on that thought? In your opinion, what are the greatest 
roadblocks to ensuring access to our vast oil and gas resource base?
    Answer. Technological developments, particularly horizontal 
drilling and hydraulic fracturing, have unlocked resources previously 
believed to be inaccessible or uneconomical to produce. Hydraulic 
fracturing was developed by small, enterprising U.S. companies in the 
1940s, finding early success stimulating oil wells in our home state of 
Oklahoma and neighboring Texas. In the 1970s, as Senator Franken 
correctly noted, DOE-funded research explored ways to tap natural gas 
resources in shale formations.\1\ For example, projects such as the 
Eastern Gas Shales Project of 1976 studied means to extract gas from 
the low-permeability Devonian shale plays of the Appalachian Basin. 
Building upon the industry's prior work on hydraulic fracturing, the 
micro-seismic mapping and high-volume well stimulation techniques 
developed under the public-private Unconventional Gas Research Programs 
laid much of the groundwork for modern drilling practices.
---------------------------------------------------------------------------
    \1\ ``DOE's Unconventional Gas Research Programs 1976-1995: An 
Archive of Important Results.'' National Energy Technology Laboratory, 
U.S. Department of Energy. January 31, 2007.
---------------------------------------------------------------------------
    The support provided by the federal government in the 1970s was, by 
all measures, a tremendous economic success for our country. As noted 
in a 2001 report by the National Research Council entitled Energy 
Research at DOE: Was It Worth It? Energy Efficiency and Fossil Energy 
Research 1978-2000,\2\ the collaborative programs resulted in billions 
of dollars in incremental state and federal tax revenues, trillions of 
cubic feet of incremental gas supply, and billions of dollars in 
consumer savings. The relatively small investment in research-$220 
million spent in total across several resource areas-has been returned 
many times over by American industry, resulting in billions of dollars 
of benefit to the country.
---------------------------------------------------------------------------
    \2\ National Research Council. Energy Research at DOE: Was it Worth 
It? Energy Efficiency and Fossil Energy Research 1978-2000. Washington, 
DC: The National Academies Press, 2001.
---------------------------------------------------------------------------
    While government and the petroleum industry have partnered 
effectively in the past, headwinds to further progress remain. Current 
regulations restricting access to oil and gas exploration on federal, 
offshore and Native American lands inhibit our Nation's ability to 
achieve energy independence. As you poignantly noted on the 16th of 
last month, the livelihood of families living and working along the 
Kuskokwim River is adversely impacted by a dearth of fuel supplies; 
yet, these families reside in the backyard of our Nation's largest 
untapped petroleum reserves. In the collaborative spirit of the 1970s, 
federal support for production on these restricted lands would prove to 
be an economic boon to both local communities and the Nation as a 
whole. Furthermore, by utilizing modern best practices and 
environmentally-conscious technologies such as Continental's ECO-Padr 
drilling, U.S. independent producers would be able to unobtrusively 
develop these vast resource plays while minimizing their collective 
footprint on the environment.
    Question 2. Transporting Crude-As the largest oil producer in the 
Bakken region-and a producer that has grown tremendously in recent 
years-I'm curious about your approach to transporting crude to 
refineries. Does Continental Resources have a preferred method for 
transportation, whether pipeline, rail, barge, or some other method?
    Answer. Continental Resources has adopted a portfolio approach with 
respect to both the mode of transportation and the various refinery 
regions we target when selling our crude oil.
    In the Bakken, it became clear several years ago that forecasted 
production would likely ramp up quicker than the region's pipeline 
take-away and local refining capacity. Since new pipeline construction 
timelines are measured in years and not months, producers such as 
Continental were required to develop alternative transportation 
strategies to move barrels to the market and avoid the prospect of 
shutting in oil wells.
    Fortunately, the Bakken region did have in place an extensive 
railroad network that had been built originally to move agricultural 
products, lumber and coal across the country. Since incremental crude 
take-away capacity was urgently required and railroad loading 
facilities could be completed in less time than new pipeline systems, 
Continental used this solution to move much of its oil to the 
marketplace.
    Today, as new pipeline and rail loading facilities enter service, 
Bakken take-away infrastructure bottleneck issues are being resolved, 
providing our company additional flexibility to transport the oil we 
produce to refinery markets throughout America. A significant portion 
of our Bakken barrels are consumed by coastal U.S. refiners in place of 
foreign barrels, which helps our national economy and 
security.Ultimately the decisions made as to where and how our 
production is sold are driven by the marketplace. Our goal at 
Continental Resources is to transport our high-quality Bakken barrels 
to locations where they are needed most, in a safe and efficient manner 
to keep costs down.
    Question 3. Pipeline Infrastructure--Testimony at this hearing 
discussed the impacts to gas prices from transportation costs to get 
crude oil to refineries throughout the country. Please describe any 
issues your company has experienced making sure crude oil gets to 
market.
    Answer. Continental Resources is predominantly a producer of light-
sweet crude oil from the U.S. mid-continent and Rocky Mountain regions. 
Traditionally, much of the high-quality crude we produced was refined 
in mid-America. But in the past five years or so many billions of 
dollars have been spent by refiners in the U.S. mid-continent region to 
displace domestic light-sweet crude demand with less-expensive heavy-
sour bitumen or syncrude produced from mines or upgraders in Canada.
    Continental responded to these changing regional refinery slates 
and new competition for pipeline space from bitumen producers north of 
the border by supporting rail transportation alternatives and 
committing to new pipeline projects with access to additional markets. 
As an example, our company is currently the largest supplier of Bakken 
crude to Puget Sound refiners as they seek alternative domestic crude 
supplies to replace declining Alaskan North Slope production.
    U.S. consumers and businesses benefit from lower gasoline and 
petroleum product prices when crude oil transportation infrastructure 
from the well to the refinery becomes more efficient, regardless of 
where the refinery is located.
    Question 4. Production/Tax Hikes--The President and many members of 
the Senate have proposed significant tax hikes on oil and gas 
producers. Can you explain what that would mean for your company? How 
would it impact your ability to explore and produce American resources?
    Answer. President Obama's energy tax increase proposal would have a 
devastating effect by reducing exploration and production investments 
in domestic oil and gas development across the industry. The result 
will be reduced domestic energy supplies, a loss of thousands of high 
paying jobs, an increase in our foreign trade deficit and, ultimately, 
higher energy prices for the American consumer.
    Independent producers, such as Continental Resources, drill 95% of 
the wells in the U.S. (Independent Petroleum Association of America) 
and these producers routinely invest more than twice their annual 
earnings into production activities. Because of the tax treatments 
currently in place for these domestic producers, the industry has been 
extremely successful in expanding oil and natural gas reserves in 
America and driving an economic boom across the country.
    During the past several years, our Nation has made significant 
strides in reducing our reliance on foreign oil. The positive economic 
effects of this trend are reflected in our improved trade balance, 
employment and tax revenue numbers. While we believe taxes that target 
domestic energy producers are counterproductive to achieving energy 
independence, we think any tax hikes levied on oil and gas producers 
while our country is in the midst of a domestic energy-fueled recovery 
would be particularly ill-timed. One specific energy tax proposal that 
would have the most devastating effect on our recovery would be the 
repeal of intangible drilling cost (IDC) deductions. This tax 
treatment, which has been in place for nearly 100 years, allows 
companies to recover investment costs quickly so they can be reinvested 
into additional drilling activity. Over the next decade, the loss of 
IDCs means the loss of 9 billion barrels of oil equivalent production; 
10,000 wells; 265,000 jobs; and $407 billion in capital expenditures in 
the U.S. economy (Woods Mackenzie).
    The President's proposed energy tax increases move us away from 
energy independence, lead to the loss of jobs and investment, and 
threaten the American energy renaissance that we are currently 
enjoying.
    Question 5. Federal vs. State/Private Lands--I noted in my opening 
statement that private and state production has soared in recent years, 
but federal lands have not kept pace. How much production does your 
company have on federal lands? Is it more difficult to obtain 
permission to produce there? If so, how so?
    Answer. Continental Resources currently produces less than 5% of 
its oil and gas on federal lands. Wells drilled on federal/public lands 
require permission in the form of Applications for Permit to Drill 
(APD's) from the Federal Bureau of Land Management (BLM). These APD's 
require more paper work than state or private wells in the application 
process and can take from 120 to 180+ days (compared to 2-3 weeks for 
state permits) to process and receive permission to drill. These 
additional filing requirements and the longer application turnaround 
times discourage development of federal oil and gas reserves compared 
with similar prospects on non-federal land. The Montana and Dakota BLM 
offices have been reported to have a backlog of 300-400 APD's on 
federal lands.
       Response of Jeffrey B. Hume to Question From Senator Udall
    Question 1. As many of my colleagues here on the committee have 
heard me say again and again, I believe that Colorado is truly a model 
for the United States in its pursuit of a balanced approach to domestic 
energy development. As we work toward achieving true energy self-
reliance through expanded domestic oil development, it is important 
that we do so in a manner that is safe and responsible. So my question 
for the industry is: as oil and gas exploration, production and 
refining continues to expand in the United States, what is the industry 
doing to develop new methods and technologies to ensure that our air 
remains clean, our water is fresh and our communities are safe?
    Answer. At Continental Resources safety and responsibility are 
deeply engrained in our culture. We take seriously our responsibility 
to work with the public, the government, and others to develop our 
natural resources efficiently and in an environmentally sound manner, 
while protecting the health and safety of our employees and the 
communities where we operate.
    We remained focused on:

   Promoting an injury/illness free workplace
   Environmental Protection
   Regulatory Compliance

    At Continental Resources we continuously look for ways to improve 
the compatibility of our operations with the environment. We pioneered 
ECO-Padr drilling, a technique whereby multiple wells are completed 
from a single drilling pad, reducing environmental impact on the 
surface of the land. This type of drilling is typically more expensive 
than conventional vertical techniques; as a result, however, we have 
fewer rig movements and our operations end up being much less 
intrusive. In addition, through proactive strategies in the Bakken 
field in North Dakota we have been a leader in the reduction of natural 
gas flaring, achieving a rate a third of the industry average.
    Continental employees around the country take great pride in 
helping to improve the communities in which they live by generously 
contributing their time, talent and treasure. As an illustration of 
this spirit, within hours of the recent tornados that devastated 
communities in the Oklahoma City area where we are headquartered, a 
successful company-sponsored disaster relief fund was established, and 
in-house coordinators helped direct employee teams to where their 
efforts were needed most.
       Response of Jeffrey B. Hume to Question From Senator Risch
    Question 1. EPA's proposed percentage bio blending standard for 
gasoline and diesel combined is 9.63% for the year 2013. The Energy 
Information Administration (EIA) has told Congress that virtually all 
ethanol blending with gasoline is at the 10% level. However, EIA has 
also stated that biodiesel blending is RIN deficient. So if a refiner 
produces a higher percentage of diesel, there is no possible way to 
meet EPA's proposed standard unless they buy credits. These credits 
that used to cost pennies per RIN gallon now cost over a dollar with 
predictions that RINs will go over $3.00 in 2014.
    a) Please give us your thoughts on the unfairness and the 
unintended consequences of the Renewable Fuel Standard.
    b) What suggestions do you have for changes that will correct this 
problem?
    Answer. As an independent exploration and production company, we 
believe our place in the petroleum supply chain renders us unqualified 
to provide an opinion on RINs or a means to improve the RFS. However, 
we will note that in our ``upstream'' crude oil production role, we 
have observed instances where well-intentioned regulations have 
resulted in market distortions; rules designed to benefit one market or 
party have had the unforeseen consequence of impairing another. 
Generally speaking, we favor more open markets to less, as they 
eliminate opportunities for some participants to exploit artificial 
distortions for personal gain contrary to the greater public interest.
                                 ______
                                 
      Responses of Faisel Khan to Questions From Senator Murkowski
    Question 1. WTI/Brent Spread--The difference in prices between WTI 
and Brent crudes has narrowed significantly in recent weeks.
    a. What do you expect will be the market-related impacts, if any, 
of this trend?
    b. Do you expect WTI and Brent prices to remain in close proximity, 
or do you expect them to again diverge in the months ahead?
    Answer. The narrowing of the crude differential more recently is a 
result of infrastructure being put into service to deliver more crude 
from Cushing and the Permian to the Gulf Coast. This narrowing is 
resulting in better pricing at the well head in certain producing 
areas. We believe these higher prices will act as a positive feedback 
loop into lower 48 production. Furthermore, higher prices also result 
in higher profits, higher royalties and higher taxes.
    We expect WTI and Brent prices to remain in close proximity ($0-$6 
per barrel) through the first half of 2014. We believe the differential 
could widen again in the second half of 2014 as the balance between 
infrastructure capacity growth and lower 48 production growth changes.
    Question 2. Technical vs. Political Risk--When assessing the 
downside risks to rising U.S. production, how do you as an analyst 
weigh the differing threat levels from geological/technical concerns on 
the one hand, and political or ``above ground'' risks on the other?
    Answer. We assess the technical and geologic concerns surrounding 
oil production growth through state, federal, industry, environmental 
and academic studies done on hydraulic fracturing, water handling, 
surface impacts and emissions. In our view, it is in the energy 
industry's best interests to operate safely, efficiently and 
responsibly. We monitor these issues closely to ascertain the risks to 
our production growth estimates.
    We assess the ``above'' ground risks by monitoring the effects of 
current laws (federal and state), policy and treaties. We also take 
into account proposed legislation and voter sentiment surrounding US 
energy production. In our view, the key variables that could affect 
energy production in the US are tax policy and potential regulation on 
drilling activity.
         Response of Faisel Khan to Question From Senator Udall
    Question 1. Over the past two decades, we've seen fast growth in 
the use of Compressed Natural Gas (CNG) in transportation as a 
replacement for diesel in heavy-duty trucks and buses. This is 
happening in some towns in Western Colorado that have switched some of 
their city vehicle fleets over to CNG, because it is a cheaper 
alternative to gasoline when prices are $4 or more a gallon. Do you see 
the same trends? If so, how might these trends affect the demand, and 
price, for gasoline and diesel over the next decade?
    Answer. We addressed some of the potential for the substitution of 
natural gas for diesel in our original testimony. We estimate LNG and 
CNG heavy duty trucks could represent 50% of truck sales in the next 
ten years. This assumes the price differential between natural gas and 
diesel on an energy equivalent basis remains unchanged from current 
levels. In our view, US domestic natural gas has the potential to 
displace 1.8mmbls/d of domestic diesel consumption by 2025.
      Responses of Faisel Khan to Questions From Senator Barrasso
    Question 1. You testified that the Keystone XL pipeline ``has faced 
unprecedented delays.'' However, you go on to say that ``the delay in 
Keystone will not stop crude production growth in Canada and the U.S.'' 
You note that ``[t]he decision to delay Keystone only allows other 
mediums of transportation such as rail, barge, and trucking to be more 
widely used'' and that ``the delay only forces producers to look at 
alternate pipeline routes.'' Finally, you state that ``[a]s more 
Canadian crude gets delivered to the coastal markets, it will enter the 
global market and the U.S. could lose a dedicated supply source.'' 
Would you expand upon the importance of Keystone XL in ensuring that 
Canada remains a dedicated supply source of crude oil for the U.S.?
    Answer. We believe the Keystone XL pipeline enables Canadian oil 
production to be refined in the US rather than being diverted to other 
countries that may have poor environmental track records. In the long-
run, we believe the pipeline reduces the amount of crude that would 
otherwise be moved by rail and marine vessels. The pipeline also 
increases the amount of trade between our two countries. Light products 
manufactured in the US are shipped to Canada in order to facilitate 
shipping heavy crude on pipelines destined for the US Gulf Coast and 
the interior US.
    Question 2. You testified that ``the Jones Act has clearly become 
an impediment to moving new U.S. crude to the coastal refineries that 
could use it.'' You explain that it ``has the effect of increasing 
gasoline and diesel prices in the U.S. because of the added cost of 
transportation.'' You go on to say that under the Jones Act, it costs 
as much as six times what it would otherwise cost to ship crude between 
U.S. ports. Would repealing the Jones Act help lower gasoline and 
diesel prices in some regions of the U.S.?
    Answer. We do not believe repealing the Jones Act would necessarily 
reduce gasoline prices across the entire nation. However, a change in 
the Act to allow non-Jones Act vessels might reduce the cost of moving 
surplus gasoline and diesel production from the Gulf Coast to the US 
East and West Coasts. This could result in lower prices for certain 
coastal markets. Separately, the remaining refineries on the East Coast 
might be able to lower their crude acquisition costs by using non-Jones 
tankers to move crude from the Gulf Coast to the East Coast, which 
would allow these refiners to compete more effectively in the Atlantic 
basin refining market. Overall, we believe a change in the Jones Act to 
allow more vessels to move both crude and refined products between US 
ports reduces the cost of transportation with the potential in passing 
these cost savings on to consumers and refiners.
        Response of Faisel Khan to Question From Senator Manchin
    Question 1. Mr. Kahn, you raise an important point in your 
testimony about crude oil spills, and I want to make sure it's 
highlighted for the committee. You quote the Manhattan Institute of 
Policy research as having found that ``incidents''--which I take to 
mean spills or other problems-are 4 times as likely to happen when the 
oil is transported by rail as opposed to being transported by pipeline. 
When oil is transported by truck, the likelihood is even higher: we are 
40 times more likely to have a spill than if we transport it by 
pipeline.
    I think that's something we should all think about when we discuss 
whether we should approve the construction of the Keystone XL pipeline.
    You also discuss how pipeline companies are trying to find other 
workarounds to reduce bottlenecks in crude oil transportation, by 
reversing flows of certain pipelines and other means. Can you comment 
on what the risks and potential environmental impacts of building a new 
pipeline might be, as compared to finding these other workarounds? I 
would think a new pipeline-like the Keystone XL-would be less at risk. 
Is that the case?
    Answer. Building a new pipeline generally requires new rights of 
ways. However, in many instances, new pipelines can be built along 
existing utility corridors or on existing rights of ways. The delay in 
Keystone XL has caused the industry to work around the delay by 
employing rail and expanding existing systems to deal with the 
bottleneck. Putting more crude on rail eventually runs into the 
statistical probability of more safety incidences. Furthermore, putting 
more crude on existing systems can be efficient; however, one runs the 
risk of putting pressure on existing systems that have been depreciated 
over a long period of time. In theory, a new pipeline should be safer 
than an older pipeline. However, older pipelines that are well 
maintained and where the owner has made substantial investments to 
modernize its system can work just as well.
         Response of Faisel Khan to Question From Senator Risch
    Question 1. EPA's proposed percentage bio blending standard for 
gasoline and diesel combined is 9.63% for the year 2013. The Energy 
Information Administration (EIA) has told Congress that virtually all 
ethanol blending with gasoline is at the 10% level. However, EIA has 
also stated that biodiesel blending is RIN deficient. So if a refiner 
produces a higher percentage of diesel, there is no possible way to 
meet EPA's proposed standard unless they buy credits. These credits 
that used to cost pennies per RIN gallon now cost over a dollar with 
predictions that RINs will go over $3.00 in 2014.
    a) Please give us your thoughts on the unfairness and the 
unintended consequences of the Renewable Fuel Standard.
    b) What suggestions do you have for changes that will correct this 
problem?
    Answer. The RFS and the CAFe standards are at odds with each other. 
We do not believe the RFS ever envisioned the decline in gasoline 
demand that we are seeing today. Never-the-less, a combination of the 
CAFe standards and changing demographics are likely to continue to 
result in declining gasoline demand in the US. We believe this trend is 
generally positive for the US as economic growth is achieved with a 
decreasing amount of energy intensity.
    We believe the RFS does provide a positive benefit for the US 
economy. It has reduced US imports of gasoline by producing domestic 
ethanol. However, we do not see the logic in penalizing the refining 
industry for its inability to blend more than 10% ethanol into the 
gasoline pool.
    Our general view is that both the CAFe standards and RFS are 
positive for the US economy. However, neither law was designed to 
penalize the industry for meeting the goals of US energy efficiency and 
self sufficiency. In this respect, we believe the RFS should be amended 
to allow more flexibility to deliver ethanol into the gasoline pool.
                                 ______
                                 
      Responses of Adam Sieminski to Questions From Senator Wyden
    Question 1. In 2007, in Sec. 804 of the Energy Independence and 
Security Act (P.L. 110-140), Congress directed EIA to track refinery 
outages and flag those that would have a significant impact on supply. 
In 2011, before you arrived, EIA stopped tracking refinery outages. In 
your testimony before the Committee, you stated that it would cost 
millions of dollars to reinstate the refinery outage reporting 
requirement. Please provide an explanation of that estimate and itemize 
the activities, personnel, and other costs that would be involved in 
reinstating a program to track refinery outages as outlined in the Sec. 
804.
    Answer. Section 804 of the Energy Independence and Security Act 
directed EIA to track planned refinery outages using data from 
commercial reporting services. EIA produced the report until May 2011. 
A major budget reduction enacted midway through fiscal year 2011 led 
then EIA Administrator Newell to reduce or discontinue a wide range of 
EIA products.\1\ With regard to the semiannual refinery outage report, 
I understand that the decision was based on the limited value of the 
report during the cycles in which it was prepared given its exclusive 
focus on planned outages using commercially available data.
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    \1\ An overview of actions under the 2011 budget reductions are 
described in EIA's press release, Immediate Reductions in EIA's Energy 
Data and Analysis Programs Necessitated by FY 2011 Funding Cut, dated 
April 28 2011. http://www.eia.gov/pressroom/releases/press362.cfm
---------------------------------------------------------------------------
    Recognizing the current need for high-quality information on 
refinery operations in general and refinery outages in particular and 
its past experience with reporting on planned refinery outages based on 
commercially available data, EIA is now engaged in developing surveys 
and other activities that would lead to the tracking of both planned 
and unplanned refinery outages. Accomplishing this and other necessary 
work will require some significant alterations in EIA's operations. 
Specifically, EIA's data collection systems require modernization due 
to outdated systems and fundamental changes in energy activity . . .  
EIA's oil data operations are undergoing wholesale changes in order to 
address the most troubling of these concerns, as opposed to worsening 
the situation by continuing the `make do' approach of the past.
    While this work proceeds we anticipate that EIA would maintain 
vigilance regarding petroleum markets using existing EIA data, third-
party data sources as may be readily accessible, analyzing current 
market conditions and proactively communicating issues of concern 
regarding those markets through Today in Energy, This Week in Petroleum 
(TWIP), and the Short Term Energy Outlook. This approach provides 
flexibility through maintaining situational awareness of all energy 
sectors that extends beyond petroleum refinery outages.
    The Department of Energy's budget request for EIA for FY14 includes 
additional resources in several key areas critical to developing the 
market insights requested. Specifically, the request includes an 
additional $2.6 million for energy supply surveys covering all fuels, 
roughly one-quarter of which would be for the Weekly Petroleum Status 
Report (WPSR) that each Wednesday provides petroleum supply information 
through the end of the prior week, $0.5 million to conduct analysis on 
refining and gasoline markets and expand efforts to better understand 
linkages between physical energy markets and financial market activity, 
and $1.9 million for energy modeling and analysis, a significant 
portion of which would be focused on petroleum-related issues.
    Question 2. Are any statutory changes to Sec. 804 required for EIA 
to carry out an effective program or does EIA have sufficient authority 
under Sec. 804 and its underlying organic authority pursuant to the 
Department of Energy Organization Act (P.L. 95-91)? For example, Sec. 
804 requires EIA to use commercially available sources. Does EIA have 
authority to obtain information on outages directly from refiners under 
the Department of Energy Organization Act?
    Answer. As discussed in the answer to the previous question, EIA 
does not believe that semiannual reports focused exclusively on planned 
refinery outages based on commercially available data, as directed in 
Section 804 of the Energy Independence and Security Act of 2007 have 
proven to be very useful information.
    As your question suggests, EIA has broad organic authority for 
energy data collection. Specifically, the Department of Energy 
Organization Act provides the authority to collect data ``relevant to 
the adequacy of energy resources to meet demands in the near and longer 
term future for the Nation's economic and social needs.'' 42 U.S.C. 
Sec.  7135 (a)(2). EIA believes that this authority would cover 
collection of information on outages directly from refiners. As 
indicated in our response to your first question we have recently 
initiated the development of surveys and forms to collect outage data.
    Question 3. Your testimony before the Committee is that U.S. oil 
prices are set in the global market, but that hasn't been the case for 
most of the past two years. According to a recent Wall Street Journal 
article (U.S. Oil Prices: Don't Call It a Comeback, July 11, 2013), WTI 
has been trading at an average discount to Brent of over $16 a barrel. 
The WTI/Brent spread has been reported upon numerous times by EIA 
itself. If U.S. crude prices were truly set in the global market there 
wouldn't be a significant difference between the U.S. benchmark and the 
major international benchmark. How do you explain the large 
differential between the benchmark prices and your view that U.S. 
prices are set in a global market?
    Answer. U.S. crude oil prices reflect worldwide supply and demand 
conditions and like other crude oil streams they reflect the quality 
characteristics and specific transportation logistics that affect the 
cost of moving crude oil to refining centers and its value to the 
refiner in producing highly-valued products. Crude oil prices are 
quoted for a specific grade of crude oil at a specific location WTI 
prices are quotes for a light sweet grade of crude delivered at 
Cushing, Oklahoma. For many years, only a minimal differential existed 
between the price of WTI and Brent crude, which is similar in quality 
to WTI and had a similar cost of transportation from the location where 
prices were quoted (Cushing for WTI, Sullom Voe in Scotland for Brent) 
to the U.S. Gulf Coast, the nation's major refining center where both 
WTI crude and comparable seaborne crudes such as Brent were processed.
    This historically small spread between WTI and Brent prices, 
however, began changing in 2009 due to the rapid growth in domestic 
crude production. This growth overwhelmed the pipeline logistics system 
used to transport WTI crude to Gulf Coast refineries. It therefore 
became necessary to transport the incremental portion of this crude by 
much more expensive methods, such as barge, truck, or rail. A refiner 
on the Gulf Coast, however, still had the option to substitute Brent 
crude for WTI based on its delivered cost. In order for Gulf Coast 
refiners to use WTI transported by the more expensive methods, its 
price at Cushing needed to be discounted relative to Brent by an amount 
sufficient to offset the higher transportation costs of moving the 
incremental supply at Cushing to the Gulf Coast. Competition with 
international crudes therefore forced the price of WTI as quoted in 
Cushing to decline by the increased costs of delivering it to the Gulf 
Coast.
    As new infrastructure is added, we would expect these crude 
differentials to decline. Recent data indicate that some constraints 
that have previously depressed WTI crude prices compared to Brent crude 
prices have been relieved, which has resulted in a reduced WTI to Brent 
crude price differential. This has happened as terminals capable of 
handling unit trains have been added to allow expanded and more 
efficient shipments of crude oil via rail and some crude and some 
pipeline flows have been reversed and expanded. Prices for crude oil 
will continue to reflect global supply and demand forces subject to 
logistical and quality differentials that can cause spreads between the 
prices of individual crude streams to widen or narrow over time.
    Responses of Adam Sieminski to Questions From Senator Murkowski
    Question 1. U.S. Resource Base--Please summarize any revisions that 
EIA has made to the United States' projected, technically-recoverable 
oil and natural gas resource base over the past decade.
    Answer. Technically recoverable resources represent the volumes of 
oil and natural gas that could be produced with current technology, 
regardless of oil and natural gas prices and production costs. 
Economically recoverable resources are resources that can be profitably 
produced under current market conditions.
    Even though over 250 trillion cubic feet of dry natural gas were 
produced in the United States between January 1, 1998\2\ and January 1, 
2011, natural gas reserves and resources have generally been 
increasing, primarily due to the growth in shale gas reserves and 
resources. In the Annual Energy Outlook 2013 (AEO2013), the estimated 
sum of total proved natural gas reserves and unproved technically 
recoverable resources equaled 2,327 trillion cubic feet as of January 
1, 2011. Of that total, proved shale gas reserves equaled 94 trillion 
cubic feet and unproved shale gas resources equaled 543 trillion cubic 
feet for a total shale gas resource of 637 trillion cubic feet. Shale 
gas resources constitute 27 percent of total U.S. natural gas 
resources, with the remaining 1,690 trillion cubic feet of natural gas 
resources distributed among the conventional, tight (low permeability), 
and coalbed methane resources.
---------------------------------------------------------------------------
    \2\ Reserves and resources in the AEO have a two year lag, for 
example AEO2000 reserves and resources were as of January 1, 1998 and 
AEO2013 reserves and resources were as of January 1, 2011.
---------------------------------------------------------------------------
    Prior to the advent of widespread shale gas drilling and 
production, the AEO2000 estimated total natural gas resources of 1,597 
trillion cubic feet as of January 1, 1998. In the AEO2000, shale gas 
resources constituted 52 trillion cubic feet, which was only 3 percent 
of total natural gas resources, and thus shale gas resources grew 1,125 
percent between AEO2000 and AEO2013. Even though the growth in natural 
gas resources is largely due to the growth in shale gas resources, 
conventional, tight, and coalbed methane natural gas resources grew 
from 1,545 trillion cubic feet in the AEO2000 to 1,690 trillion cubic 
feet in the AEO2013, a 9 percent increase.
    EIA's estimate of the sum of U.S. proved crude oil resources plus 
unproved technically recoverable crude oil resources has increased from 
140 billion barrels in the AEO2000 to 223 billion barrels in the 
AEO2013, even though over 26 billion barrels of oil were produced over 
that timeframe. It is more difficult to make direct comparisons across 
the AEO oil categories because some of the oil reserves and resources 
have been reclassified as being low-permeability ``tight'' oil 
resources. ``Tight oil'' refers to oil resources located in low-
permeability sandstone, carbonate, and shale formations. The 
application of hydraulic fracturing and horizontal drilling to these 
tight oil formations has significantly expanded oil resources by making 
these formations economically productive under prevailing oil prices. 
Rising oil prices have also contributed to rising proved reserves. In 
the AEO2013, tight oil unproved resources account for 58 billion 
barrels or 26 percent of total oil resources.
    Even though the AEO oil resources by category cannot be directly 
compared over time, AEO2013 proved oil reserves increased by 1.3 
billion barrels over the AEO2000 estimate, a 5 percent increase, and 
including the 26 billion barrels of cumulative production this is a 115 
percent increase. In addition AEO2013 unproved, undiscovered oil 
resources increased by 81.4 billion barrels, a 70 percent increase over 
the AEO2000 estimate.
    The AEO2012 and AEO2013 both contain more detailed discussions of 
revisions to resource estimates for specific shale gas and tight oil 
plays and discussions of the inherent uncertainties in resource 
estimates. Please refer to pages 56 through 64 in AEO2012 and pages 33 
and 34 of AEO2013. The Assumptions reports for the Oil and Gas Supply 
Module for each AEO also provide details about specific changes in 
resource estimates.
    Question 2. Transporting Crude Oil--How do the transportation 
options for crude oil (including pipeline, rail, and barge) vary in 
terms of cost? Is there a specific mode that industry appears to 
prefer?
    Answer. From 2005 to 2010, 96 percent of refinery crude oil 
receipts came by pipeline and tanker (ship). With relatively low cost 
and high capacity, pipelines have long been the delivery method of 
choice for inland refineries. Coastal refineries, on the other hand, 
have typically been served by tankers of waterborne imports or offshore 
production. This began to change in 2011 and by 2012, pipeline and 
tanker deliveries accounted for 93% of the total with the remainder 
being deliveries of domestic crude via barge, rail, and truck. Truck 
and rail movements accounted for 3 percent of the total and barge 
receipts for 3 percent. We believe the increase in barge movements may 
be explained, at least in part, by crude loaded on rail cars at 
production areas and then transferred to barges for the final leg of 
delivery to refineries on the East Coast and along the Mississippi 
River.
    The cost of transporting crude via any of the above methods varies 
widely depending on the distance traveled, the type of crude being 
transported, and the terrain over the transport distance, and other 
factors. EIA cannot accurately provide such cost data at this time.
    Question 3. Increasing Gasoline Prices--Many recent news stories 
have suggested that last week's increase in gasoline prices will 
continue in the weeks ahead. In EIA's estimation, what are the various 
factors that are combining to push prices higher?
    Answer. While the pump price of gasoline is influenced by a variety 
of factors, including changes in fuel specifications and fuel taxes, 
the major long-run determinant of gasoline prices is the global price 
of crude oil. In the last 10 years, the average price for gasoline in 
the U.S. has risen a little over $2 per gallon, while the price of 
Brent crude oil, the international benchmark for waterborne light sweet 
crude oil has gone up $1.87 per gallon. Over shorter time horizons, 
other factors that influence the price of gasoline include refinery 
operations, seasonal demand patterns, inventory levels, financial 
market activity, and distribution operations.
    For the week ending July 22, 2013, the average price in the U.S. 
for regular grade gasoline was $3.68 per gallon. This was an increase 
of almost 19 cents per gallon from July 1 as compared to a 13 cent per 
gallon increase in the price of Brent crude oil during the same time 
period. Since June, average gasoline prices are up by 4 cents per 
gallon while Brent crude prices have increased by 15 cents per gallon. 
While the direction of both crude and gasoline prices are uncertain at 
this time, we are aware of the increased tensions in the Middle East, 
which are being monitored closely by the international crude markets.
    Question 4. Spare Capacity--How has global spare capacity for oil 
production changed over the past five years? Has this change had a 
stabilizing influence on world oil prices?
    Answer. Global spare production capacity for crude oil has varied 
greatly over the last five years. EIA estimates that spare capacity 
reached a low point of just below 1 million barrels per day at the 
beginning of this time frame, in the third quarter of 2008, amidst the 
all-time highest recorded prices for the Brent and WTI crude oil 
benchmarks. EIA estimates that the highest spare production capacity in 
the last five years was in the fourth quarter of 2009, when it reached 
4.4 million barrels per day during the recovery from the financial 
crisis earlier that year. Spare production capacity generally declined 
from that point until the third quarter of 2012. EIA estimates that 
current global crude oil spare production capacity is about 2.2 million 
barrels per day.
    In general, higher crude oil spare production capacity is 
associated with lower crude oil price volatility but there are many 
other factors that can affect price stability, such as uncertainty over 
future economic growth as well as supply disruptions. Anticipated spare 
capacity is another consideration. With growth in production by non-
OPEC producers, including the United States, expected to exceed growth 
in global oil demand during 2013 and 2014, global spare capacity is 
expected to increase over the next 18 months in the absence of major 
supply disruptions or unexpected demand growth. The outlook for growth 
in spare capacity together with a moderate outlook for global economic 
growth has likely contributed to recent relative stability in crude oil 
prices
    Question 5. Production/Volatility--I noted in my opening statement 
that a recent Wall Street Journal analysis found rising American oil 
production has reduced volatility in world oil prices. Do you agree 
that American oil production had a positive impact in minimizing crude 
price volatility?
    Answer. Rising crude oil production in the United States has helped 
moderate prices over the last two years. For example, domestic crude 
oil production was 850,000 barrels per day higher in 2012 compared to 
2011, largely due to the dramatic growth in tight oil that has only 
recently been recognized as an economically attractive resource. 
Increased U.S. production was roughly equal to the total growth in non-
OPEC crude oil production in 2012, a year in which global spare 
production capacity was relatively tight given the effect of sanctions 
on Iran and production disruptions in countries including Sudan, South 
Sudan, and Syria. Absent the 2012 increase in U.S. production, already-
low global spare capacity in 2012 would have been nearly cut in half, 
creating a significant prospect for world oil prices well above the 
levels that were actually realized.
    Question 6. In your testimony, you briefly discuss the impacts of 
unplanned refinery outages on gasoline prices and describe price 
impacts as ``relatively short-lived.''

    a. In your experience, when unplanned outages occur, causing gas 
prices to increase, how long do these price spikes last? In your 
opinion, is there anything that can be done to address this issue?
    b. In your experience, do planned outages--referred to as 
``turnarounds''--have similar impacts on gas prices?
    Answer. When a turnaround exceeds its planned timing or when a 
refinery outage occurs unexpectedly, the effect on petroleum product 
supplies and pricing can at times be significant, but usually not long-
lasting. All areas of the country can be supplied with petroleum 
products from alternate refining centers, but such supplies often take 
some time to arrange and transport and are likely more costly than 
products from the usual supply sources that were disrupted. While no 
two outages are exactly the same, we have analyzed four such events 
that occurred on the West Coast between 2008 and 2012 and found that 
the price effects lasted from 6 to 10 weeks with an average of about 8 
weeks in duration. The recent supply incident in the Midwest lasted 
approximately 10 weeks. As unplanned outages, these incidents are by 
their nature unpredictable such that little can be done to prevent 
them.
    Major refinery units are generally taken out of service after 3-5 
years of operation for repairs and routine maintenance. These planned 
activities, known as turnarounds, are planned years in advance in order 
to have equipment ordered and delivered and to schedule thousands of 
temporary workers, some of them highly skilled, for the work. For these 
periods of planned maintenance, refiners typically arrange for product 
supply to meet their contracted supply obligations. Resupply strategies 
include arranging for product to be supplied by other refineries in the 
area through exchange or purchase or through inventory builds prior to 
the turnaround. Also, these turnarounds are generally scheduled to 
occur when product demand is at a seasonally low level. For these 
reasons, turnarounds that do not exceed their planned time frame 
generally do not materially affect petroleum product supplies and 
prices.
       Response of Adam Sieminski to Question From Senator Udall
    Question 1. As the United States oil industry and market are 
undergoing a major transformation, what impact do these shifting 
dynamics have on the global oil market and--particularly--on our most 
important international allies?
    Answer. The most important changes occurring in the U.S. oil 
industry are increasing domestic production of crude oil and increasing 
levels of petroleum product exports from U.S. refineries.
    Domestic crude oil production in the United States has increased 
significantly over the past three years, reaching 7.4 million barrels 
per day as of April 2013, the highest level since October 1992. As a 
result, U.S. imports of crude oil from sources such as Africa, Latin 
America, and the Middle East during this period have declined. At the 
same time, imports from Canada have increased.
    In 2012, the U.S. exported some 2.7 million barrels per day of 
finished petroleum products and gasoline blendstocks, up from 1.3 
million barrels per day in 2007. Of this 1.4 million barrels per day 
increase, about 52% (740,000 barrels per day) is diesel fuel and about 
25% (360,000 barrels per day) is gasoline and gasoline blendstocks. At 
the same time, U.S. imports of gasoline, gasoline blendstocks, and 
diesel have declined by over 670,000 barrels per day. With declining 
demand for petroleum products in the United States due to fuel 
efficiency gains and increased use of biofuels, U.S. refineries 
increasingly depend on product exports to maintain high operating rates 
and profitability. The extent to which exports can grow depends on 
demand growth in the international market, the competitive position of 
U.S. refineries to serve those markets, and domestic demand. Wholesale 
gasoline and diesel will continue to reflect conditions in global 
markets, with both import and export opportunities dictated by 
differences in prices between regional market centers such as New York 
Harbor, Rotterdam, the U.S. Gulf Coast, Los Angeles, and Singapore that 
are large enough to make international shipments of products 
profitable. Such shipments generally continue to the point where 
regional product prices align so that opportunities for profitable 
arbitrage are eliminated.
       Response of Adam Sieminski to Question From Senator Risch
    Question 1. Please give us your thoughts on the unfairness and the 
unintended consequences of the Renewable Fuel Standard and what 
suggestions do you have for changes that will correct this problem?
    Answer. My June 26, 2013, testimony before the Subcommittee on 
Energy and Power of the House Energy and Commerce Committee outlines 
EIA's views regarding the Renewable Fuel Standard (RFS) program. While 
I would refer you to the testimony for a complete perspective, four of 
its main points are briefly summarized below.
    First, the RFS program is not projected to come close to 
achievement of the legislated target of 36 billion gallons of renewable 
motor fuels use by 2022. This is not a new finding--all of EIA's Annual 
Energy Outlook (AEO) Reference case projections since the targets were 
enacted in 2007 have indicated that EPA would need to apply the law's 
flexibility to reduce requirements for cellulosic, advanced, and total 
biofuels.
    Second, substantial increases in biofuels can only occur in forms 
other than the low-percentage blends of ethanol and biodiesel that 
account for nearly all of their current use. Of the potential 
alternative pathways (1) increased use of higher ethanol blends, (2) 
the advent of drop-in biofuels, or (3) the development of compatible 
renewable fuel components, such as biobutanol. So far, none have 
achieved a significant market role.
    Third, the implicit premise that cellulosic and other advanced 
biofuels would be available in significant quantities at reasonable 
costs within 5 to 10 years following adoption of the 2007 RFS targets 
has not been borne out. The AEO Reference case projections do not 
assume breakthroughs in transformational biofuels technologies
    EIA has not yet been able to discern an impact on gasoline prices 
due to the large increase in RIN prices in the first quarter of this 
year. While the cost of refined gasoline blendstock can be affected by 
high RIN prices, the increased cost to gasoline blenders is almost 
exactly offset by their increased revenue generated from the sales of 
RINs that are separated when ethanol is blended into gasoline. Going 
forward, EIA would expect that efforts to achieve the escalating 
targets for biofuels use specified in the RFS legislation would likely 
cause gasoline prices to increase relative to their level in the 
absence of an escalating RFS mandate. The actual outcomes will likely 
depend on the extent to the Environmental Protection Agency exercises 
its legal authority under the RFS statute to set standards for 
cellulosic, advanced, and total biofuels below the legislatively 
specified target levels.
         Responses of Adam Sieminski to Questions From Senator
    Question 1. Can you comment on how converting vehicles to use 
natural gas as a fuel--to supplant either diesel or gasoline--might 
impact our finished product exports? I would guess that we'd export 
more products and it'd be good for our trade balance, but it could also 
result in refineries shutting down. What are your thoughts on this 
matter?
    Answer. In EIA's Annual Energy Outlook 2013 natural gas use in 
vehicles, including both the direct use of natural gas in vehicles-i.e. 
liquefied natural gas used in heavy duty vehicles-and the indirect use 
of natural gas as liquids from a gas-to-liquids process, reaches 1.7 
trillion cubic feet by 2040, displacing 0.7 million barrels per day of 
other motor fuels, principally diesel fuel. Over the same period, 
diesel fuel consumption increases by 0.8 million barrels per day, 
primarily for use in heavy duty vehicles, offsetting the displacement 
diesel fuel by natural gas. As a result, EIA does not expect the 
increased use of natural gas as a motor vehicle fuel to result in 
refinery shutdowns. Even if higher amounts of traditional petroleum 
fuels were displaced by increased natural gas use, the ability to 
export petroleum products could avoid the need to close refineries as 
long as they remained competitive in the global markets.
    Question 2. Can you comment on how a technology like advanced EOR 
can extend the life of our oil fields? Or discuss other research areas 
that can help us get the most bang for our buck from these fields, and 
keep the oil flowing?
    Answer. Technology development within the oil and natural gas 
industry is an ongoing process involving both the Federal laboratories 
and the research and development activities undertaken by oil and 
natural gas production and service companies. Almost all of the current 
EOR production results from the injection of either steam or carbon 
dioxide (CO2) to improve oil field recovery rates.
    The greatest current constraint to higher CO2 EOR 
production is the lack of affordable CO2 supply. If more 
CO2 supply were available to oil producers at affordable 
prices, then CO2 EOR investment and oil production could 
increase significantly. Both the Department of Energy laboratories and 
private industry are devoting substantial research dollars to develop 
more efficient and economic technologies to capture and concentrate 
CO2 from fossil fuel combustion flue gases at electric power 
plants and at industrial manufacturing facilities. This research and 
development could have a great impact on increasing future oil 
production if it removes current constraints on CO2 supply 
and makes significant new sources of CO2 available to oil 
producers at affordable prices.
    Two other areas of current EOR research also merit attention. The 
first of these is focused on supplementing steam and CO2 EOR 
injection with the co-injection of chemical surfactants to further 
reduce oil viscosity, thereby further enabling the movement of oil to 
production wells. This research is still at an early stage and will 
require considerably more research and testing before it could be 
widely implemented.
    Another avenue of steam and CO2 EOR research is the 
better monitoring and characterization of the movement of fluids 
through oil reservoirs so that the bypassed oil in the reservoir can be 
produced. Better monitoring could be achieved with the better and less 
expensive downhole instrumentation and surface seismic equipment. 
Research efforts are underway to reduce the cost of downhole 
instrumentation and seismic equipment so that that they can be used 
more widely and frequently. The better characterization of fluids 
movement through the reservoir is being achieved through the research 
and development of better reservoir simulator software that show how to 
increase and optimize the movement of fluids through the reservoir.
                              Appendix II

              Additional Material Submitted for the Record

                              ----------                              

              Statement of Congressional Research Service
    This memorandum is written in response to your request for an 
analysis of crack spreads at U.S. refineries, over time, organized by 
Petroleum Administration Defense District (PADD).\1\ Crack spreads 
calculated for this memorandum compare revenues earned by refineries 
from the sale of gasoline and diesel fuel to the cost of a variety of 
crude oils, including the composite value of domestic and imported oil 
as reported by the Energy Information Administration (EIA) as the 
refiner's acquisition cost of crude oil, West Texas Intermediate (WTI), 
and Brent crude oil. Monthly crack spreads were calculated for 2012.
---------------------------------------------------------------------------
    \1\ PADD 1 is the East Coast. PADD 2 is the Midwest. PADD 3 is the 
Gulf Coast. PADD 4 is the Rocky Mountains. PADD 5 is the West Coast.
---------------------------------------------------------------------------
Crack Spreads
    Crack spreads are a simple, although incomplete, measure of 
refinery profitability. The simplest crack spread is the 1:1 spread 
which represents the refinery profit margin between a key product, 
usually value of gasoline, and the cost of crude oil. The 
incompleteness of this spread in measuring profit is seen by 
considering what is left out of the calculation. When a refinery 
processes a barrel of crude oil, over a dozen petroleum products are 
produced, although about 75 percent of the production output consists 
of gasoline and distillates. Each of these products has an economic 
value that contributes to the revenue side of the profit calculation. 
While crude oil represents about two thirds of the refinery's costs, 
labor, energy and other operating costs must also be met. As a result, 
a 1:1 crack spread is only a rough measure of likely profitability.
    When considering a crack spread that more accurately reflects the 
output of a refinery, multiple products and their relative yields at 
the refinery should be accounted for. A 3:2:1 spread better reflects 
the yield of a typical refinery in that production yields double the 
amount of gasoline compared to distillates. This crack spread is 
calculated as the value of two barrels of motor gasoline plus one 
barrel of No. 2 distillate minus the cost of three barrels crude oil. 
Although this measure profitability remains incomplete, it does account 
for approximately 75 percent of the revenue earned by refinery.
    If the calculated 3:2:1 crack spread has a positive value, this 
indicates the possibility of overall profitability for the refinery. If 
the value of the spread is negative, losses due to refinery operations 
are likely.


[GRAPHIC(S) NOT AVAILABLE IN TIFF FORMAT]


                                 ______
                                 
                     Statement of Matthew Chesnes*
---------------------------------------------------------------------------
    * Email: [email protected]. Web: http://www.chesnes.com. I thank 
John Rust, Ginger Jin and Peter Cramton for their support. I am also 
grateful to Louis Silvia, Chris Taylor, Nick Kreisle, David Meyer, 
David Schmidt, and seminar participants at the Federal Trade 
Commission, the University of Maryland, the Federal Reserve Board of 
Governors, and La Pietra-Mondragone Workshop in Economics for their 
suggestions and comments. All remaining errors are my own. The opinions 
expressed here are those of the author and not necessarily those of the 
Federal Trade Commission or any of its Commissioners.
---------------------------------------------------------------------------
Abstract
    This paper considers the effects of refinery outages (due to 
planned turnarounds or unplanned events) on current petroleum product 
prices and future refinery investment. Empirical evidence on these 
relationships is mixed and highly dependent on the size and duration of 
the outage, the geographic area considered, the level of inventories 
available at the time of the outage, and the tightness of the market as 
measured by the capacity utilization rate. Using a detailed database of 
plant-level refinery outages for both upstream and downstream refining 
units, I estimate the effects of outages on product prices controlling 
for the crude oil price and the ability of operating plants to respond 
to the outage. I also consider the effect of current market 
profitability on the likelihood of planned refinery outages and the 
effects of high utilization rates and planned maintenance on the 
likelihood of unplanned outages. I then use plant-level capacity data 
to analyze the effects of outages, profitability, and utilization rates 
on future investment decisions of the refinery.
    Results based on OLS and probit models show that planned outages 
tend to occur during the spring and fall and during times of relatively 
low margins as measured by the crack spread. The length of time since 
the last plant turn-around is positively associated with future 
unplanned outages. Price regressions show that atmospheric distillation 
and catalytic cracking outages have positive effects on gasoline prices 
and these effects are larger the higher is the utilization rate at the 
time of the outage. The relationship between investment and (recent) 
past outages is weak, suggesting that refiners may be responding to 
longer-term trends in the operations and profitability of their plants.
                              Introduction
    The United States is the largest consumer of crude oil in the world 
and this resource accounts for 40 percent of the country's total energy 
needs.\1\ Although a majority of this oil comes from foreig11 sources, 
almost all is refined domestically. Refineries distill crude oil into a 
large number of products such as gasoline, distillate (diesel fuel and 
heating oil), and jet fuel. While much attention has been paid to the 
upstream crude oil production industry (see Hamilton (1983) and Hubbard 
(1986)), and the downstream retail sector (see Borenstein (1991 & 
1997), Lewis (forthcoming), Noel (2007), and Chesnes (under review), 
very little research has focused on the role of the refining industry. 
In the short-run, refiners face a complicated linear progTamming 
problem of optimizing their operations using multiple types of crude 
oil, various configurations of upstream and downstream refining units, 
and many refined products whose prices are constantly changing.\2\ This 
challenging problem is made even harder when considering the potential 
for full or partial plant outages which frequently occur. Over the 
longer term, refiners are also optimizing over the size of their plant, 
making investments in the capacities of upstream and downstream units 
to both process more crude oil and to have the flexibility to use 
different types of crude oil and change their output slate in the face 
of relative price changes. This paper considers the relationship 
between refinery outages, utilization rates, price spreads, and 
investment.
---------------------------------------------------------------------------
    \1\ Source: 2007 Annual Energy Review, Energy Information 
Administration (EIA).
    \2\ Different types of crude oil are better adapted to producing 
certain refined products. Plants are heterogeneous in their complexity 
so some are able to process a wider variety of crude oils.
---------------------------------------------------------------------------
    The optimal choice of capacity accumulation, i.e., the increased 
ability to distill crude oil into higher valued products, is a long-
term decision. Capacity is expensive to build and may take time to come 
online so forecasts of future market conditions are crucial. A shorter-
term problem involves a refiner's choice of capacity utilization. This 
rate measures the intensity with which a firm uses its capital, which 
for a refinery may include the use of boilers, distillation columns, 
and downstream cracking units.\3\ In addition to planned outages that 
involve a plant going offline for preventative maintenance, unplanned 
outages also occur that can affect the entire plant or just individual 
units.\4\ Since a refiner is interested in maximizing the profits of 
the plant, the prices of both inputs (crude oil and oxygenates) and 
outputs (gasoline, diesel fuel, etc.) are crucial to the short-run and 
long-run production and investment decisions. The crack spread, or the 
difference between the prices of crude oil, gasoline, and heating oil, 
is a proxy for the profitability of turning a barrel of oil into 
higher-valued products.
---------------------------------------------------------------------------
    \3\ More details on the refining process can be found in the next 
section.
    \4\ A refinery is generally composed of an upstream atmospheric 
distillation unit that first separates the crude oil and many 
downstream units, such as cracking units, hydrotreaters and reformers 
that further process the crude into higher-valued products. Though an 
upstream outage can have a domino-effect on downstream units, 
refineries can also buy feedstocks from other plants to partially 
mitigate the outage.
---------------------------------------------------------------------------
    I first consider planned outages (also called turn-arounds) at US 
refineries. There is strong seasonality in the demand for refined 
products and refineries tend to choose to schedule planned turn-arounds 
when demand is low and spare capacity or product inventories can fill 
in for the lost production. However, refiners also face uncertain 
demand and may push back or move up planned outages when profitability 
(as measured by the crack spread) is relatively high or low 
respectively. However, shocks, such as hurricanes can and do occur, 
sometimes during periods when there is little excess capacity. 
Therefore, I next focus on unplanned outages. While weather events can 
occur randomly and affect a large number of plants, other idiosyncratic 
outages that only affect one plant (such as a refinery fire) may be 
related to the utilization rate at which the plant is running or the 
time since the plant last performed a turn-around.\5\
---------------------------------------------------------------------------
    \5\ Unfortunately, I do not observe plant-level utilization rates, 
but I do observe utilization rates at the refining district level. 
However, even these utilization rates only reflect the rate of 
atmospheric distillation (the first phase of refining) and not the 
production intensity of downstream units.
---------------------------------------------------------------------------
    Once I understand when and why outages occur, I then focus on the 
effect of the outages on product prices. Some studies (EIA, (2011)) 
have found very little correlation between outages and product prices 
with crude oil price fluctuations being the primary driver of the 
variation in product prices. One benefit of the detailed outage data 
that I employ is that outages are reported by refining unit. Since some 
units (such as the Fluid Catalytic Cracking or FCC unit) are more 
important for the production of certain products (such as gasoline), I 
can determine how certain types of outages affect different product 
prices. Outages that occur during periods of low demand or high 
inventories likely have less of a price effect compared to periods 
where inventories are relatively low and/or utilization rates are high 
because plants are less able to respond to nearby outages. Therefore, 
my analysis will control for the level of market tightness at the time 
of the outage when assessing its impact.
    Finally, I consider the effects of outages, price spreads, and 
utilization rates on investment decisions of the refiners. I expect 
that unplanned outages during a given year might lead to future 
investment as a refiner wants to update their plant and avoid future 
outages. The crack spread is a measure of profitability so in years 
following relatively wide crack spreads, I expect more investment if 
refiners expect that profitability will remain favorable in the future. 
Investments in capacity may also be larger if a plant found it optimal 
to run at a high utilization rate in the prior year. If high 
utilization rates generally lead to more unplanned outages, then 
investing in more capacity can help avoid future outages.\6\ My data 
also allows me to study investments in both upstream (atmospheric 
distillation) capacity and and in downstream units. This is important 
because refiners may find it optimal to increase the complexity of 
their plant by investing in downstream units such as hydrocrackers and 
reformers that allow them more flexibility in their production slate.
---------------------------------------------------------------------------
    \6\ Relatively low product inventories, volatile prices, and 
investments by competing plants may also affect future investment 
decisions, but I do not focus on these relationships in this paper.
---------------------------------------------------------------------------
    While a fully structural model of the refining industry may provide 
important insights into the industry and how it responds to shocks, the 
complexity of the input and output choices, the heterogeneous 
technology, and other factors make modeling this behavior 
intractable.\7\ The reduced-form approach in this paper allows to me 
assess the relationships between key variables and gain insights into 
how the oil refining industry responds to shocks, while averaging over 
some of the variation not captured by the model (such a refiner's 
choice of different types of crude oil).
---------------------------------------------------------------------------
    \7\ In technical terms, the state space of crude and product 
prices, capacities, and inventories (to name a few) is very large. 
Modeling only a subset of these state variables masks important 
variation that is important to the refiner as he optimizes production 
each period.
---------------------------------------------------------------------------
    My results indicate that planned outages tend to occur during the 
spring and fall and during times of relatively low margins as measured 
by the crack spread. Plants need to perform annual maintenance each 
year no matter how profitable are price spreads, so with very large 
crack spreads, some plants still perform planned turn-arounds. The 
length of time since the last plant turn-around is positively 
associated with future unplanned outages. Since utilization rates are 
only available at the PADD-district level, unplanned outages are 
actually decreasing in the utilization rate, but this effect does not 
measure the impact of plant-level production intensity on future 
unplanned outages.
    Price regressions show that atmospheric distillation and catalytic 
cracking outages have positive effects on gasoline prices and these 
effects are larger the higher is the utilization rate at the time of 
the outage. Distillate prices also respond positively to atmospheric 
distillation outages, but are unaffected by catalytic cracking outages, 
a unit better-equipped for producing gasoline. Investment in certain 
refining units is positively associated with planned and unplanned 
outages of those units, but in general, the relat ionship between 
investment and past outages is weak, suggesting that refiners may be 
responding to longer-term trends in the operations and profitability of 
their plants.
    The remainder of this paper is organized as follows. In section 2, 
I provide an overview of the oil refining industry to better understand 
the complicated problem facing the refiner. I describe my data in 
section 3 and describe my empirical specifications and results in 
section 4. Section 5 concludes and provides a discussion of potential 
extensions.
2 Background on the US Oil Refining Industry
    The oil industry is broadly comprised of several vertically 
oriented segments. They include crude oil exploration and extraction, 
refineries which distill crude oil into other products, pipeline 
distribution networks, terminals that store the finished product near 
major cities, and tanker trucks which transport products to retail 
outlets.\8\ The largest refined product, gasoline, accounts for about 
55 percent of total production, while distillate makes up another 
third. A full 68 percent of output from the oil refining industry is 
used in the transportation industry. Figures 1 and 2* provide a 
description of the production process and average product yields.\9\ 
The main distillation process produces some final products like 
gasoline, but it is complemented by other units that extract more of 
the highest valued products. Technical details of the refining process 
and background on the types of crude oil available can be found in the 
appendix.
---------------------------------------------------------------------------
    \8\ 75 percent of terminals in the US are owned by companies not 
involved in the upstream exploration and refining.
    \9\ Note the motor gasoline blending components are shown here as a 
part of refinery production, even though EIA reports them as a 
(negative) input into refining since they leave the refinery as an 
unfinished product, later to be mixed with other chemicals (usually 
ethanol) by a blender.
    * All figures and maps have been retained in committee files.
---------------------------------------------------------------------------
    The market for refined oil products is large and growing, with the 
US consuming 388 million gallons of gasoline each day and one quarter 
of the world's crude oil.\10\ Aside from refining crude oil into 
gasoline, refmeries produce many products that are important inputs 
into other industries. Retail gasoline prices have recently experienced 
increased variability in the US and in summer 2008 hit an all time high 
of $4.11 per gallon. Wholesale prices peaked around $3.40 a gallon in 
the same period.\11\ Many justify the high prices as a result of the 
growing demand for gasoline and supply limitations, including the 
scarcity of crude oil, Middle East uncertainty, hurricanes, and the 
OPEC cartel. Others claim the high prices result from coordinated 
anticompetitive behavior by big oil companies. Outages, investment and 
utilization choices by oil refineries may also play a significant role 
in affecting downstream prices.
---------------------------------------------------------------------------
    \10\ Annual world consumption of crude oil totals 30 billion 
barrels, of which 7.5 billion barrels comes from the US. About 60 
percent of crude oil used by refineries is imported and US consumption 
of refined gasoline represents 40 percent of world consumption.
    \11\ US regular gasoline, source: EIA. 6 Source: EIA
---------------------------------------------------------------------------
    About one-half of US production occurs near the Gulf of Mexico in 
Texas and Louisiana, though there are significant operations in the 
Northeast, the Midwest, and California. During World War II, the 
country was divided into Petroleum Administration for Defense Districts 
(PADDs) to aid in the allocation of petroleum products. Figure 3 
displays a map of refinery locations along with delineations of the 
five PADDs and ten refinery districts.
    While retail markets for gasoline tend to be very small, markets 
for wholesale gasoline are relatively large due to the extensive 
pipeline network use to transport most refined products. While a PADD 
may have roughly approximated a market in 1945, these delineations were 
made before the pipeline network had been fully developed, so they are 
now just a convenient way to report statistics on the industry.\12\ A 
map of major crude oil and production pipelines is shown in figure 4. 
With important pipelines connecting the Gulf Coast production center to 
the population centers in the Northeast and the Midwest, PADDs I, II, 
and III are closely linked and may constitute one large wholesale 
gasoline market. The Rocky Mountain region (PADD IV) is fairly isolated 
from the rest of the country and imports only limited refined product 
from other regions. Finally, refiners on the West Coast (PADD V), which 
includes California, a state that, due to strict environmental 
regulations, are limited in their ability to use products that are 
refined in other states.
---------------------------------------------------------------------------
    \12\ For instance, the Colonial pipeline, which runs from the Gulf 
Coast up to the Northeast, was built in 1968. Pipelines now carry 70 
percent of all refined products shipped between PADDs.
---------------------------------------------------------------------------
    Aside from the domestic refining industry, US refiners face limited 
competition from abroad. While the US is very dependent on foreign oil, 
domestic production accounts for about 90 percent of US gasoline 
consumption, though the import share has grown since the mid 1990s. 
These imports come primarily into the Northeast, which receives 45 
percent of its supply from outside sources, such as the US Virgin 
Islands, the United Kingdom, the Netherlands, and Canada. Recent US 
regulations limiting certain types of fuel additives combined with 
increased European dependence on diesel fuel has limited the ability of 
US markets to rely on foreign imports.
2.1 Capacity and Utilization of US Oil Refineries
    The refining industry is fairly competit ive, with 142 refineries 
owned by 61 refining companies in January 2011. However, no new 
refineries have been built in the US since 1976. In fact, many plants 
have closed and the number of refineries ha..c; fallen from 223 in 
1985. However, most of these closures were small and inefficient 
plants, and those that remain have expanded, so total operable capacity 
has grown from 15.6 million barrels per day (bbl/day) in 1985 to over 
18 million bbl/day today (at mospheric distillation capacity). The 
overall number of refineries along with their production capacity are 
displayed in figure 5. The average plant size has increased from 74,000 
bbl/day in 1985 to almost 128,000 bbl/day in 2011. The largest refiner 
(Exxon Mobil) controls about 10 percent of the total US refining 
capacity and the top five refiners account for 43 percent of total 
capacity.
    Though the atmospheric distillation capacity of oil refineries is 
the most often cited figure when talking about the size of plants, 
downstream units are also becoming more and more important as refiners 
seek maximum flexibility in their production slate. Figure 6 displays 
the average size of downstream refining units as a proportion of total 
downstream capacity by PADD. While there are other downstream units, 
such as hydrotreaters and vacuum distillation units, these four units 
make up a majority of a normal refinery's downstream capacity. (Fluid) 
Catalytic Cracking units make the largest percentage of downstream 
capacity for all five PADDs. These units break up heavy gas oils into 
smaller and more valuable molecules. Catalytic reformers are the next 
largest group of units and these are generally used to increase the 
octane level of petroleum products. Instead of breaking down molecules 
like a cracker, reformers reconfigure molecules to make them more 
valuable. Thermal cracking and catalytic hydrocracking are the smallest 
of the downstream units, though used relatively more in PADD V. These 
also break apart chains of hydrocarbons into smaller chains either 
using heat (thermal) or using a catalyst and hydrogen (hydrocracking). 
One extreme form of thermal cracking is known as coking, which breaks 
apart heavy feedstocks into lighter oils. Hydrocrackers are relatively 
more efficient at making distillate than making gasoline.
    Capacity utilization rates at US refineries had been rising 
throughout the 1900s, but have fallen throughout the 2000s to an 
average of about 85 percent in 2011 as shown in figure 7. From 2000 to 
2008, the average utilization rate in all US manufacturing industries 
was 77 percent, so even with the recent drop, refiners still operate 
their plants at high rates.\13\ Also shown in the figure is the average 
utilization rate by month (averaged across years). It is clear that 
although annual averages have fallen, refiners still run their plants 
at a high rate during the high-demand summer driving months with 
utilization rates averaging over 90 percent.
---------------------------------------------------------------------------
    \13\ See http://jwww.federalreserve.govjreleases/G17jcaputl.htm.
---------------------------------------------------------------------------
    Building a new refinery is very expensive, and environmental 
requirements and permits create significant hurdles.\14\ Evidence from 
a 2002 US Senate hearing estimated the cost of building a 250,000 bbl/
day refinery at around 2.5 billion dollars, with a completion time of 
5-7 years (Senate (2002)). This assumes the various environmental 
hurdles and community objections are satisfied. No one wants a dirty 
refinery operating near them.\15\ In May 2007, the chief economist at 
Tesoro, Bruce Smith, was quoted as saying that the investment costs in 
building a new refinery arc so high that you'd need 10 to 15 years of 
today's margins [at the time, around 20 percent] to pay it back.''\16\
---------------------------------------------------------------------------
    \14\ 0ne of the few new plants in development is in Yuma, Arizona. 
The builder is still acquiring all the necessary permits to begin 
construction, but plans to be up and running in 2013. Another project 
in Elk Point, South Dakota is also underway.
    \15\ Commonly referred to as ``NIMBY,'' an acronym for Not In My 
Back Yard.
    \16\ The National Petrochemical & Refiners Association estimates 
that the average return on investment in the refining industry between 
1993-2002 was 5.5 percent. The S&P 500 averaged over 12 percent for the 
same period. See ``Lack of Capacity Fuels Oil Refining Profits'' 
available online at http://www.npr.org/templates/story/
story.php?storyld=l0554471 (downloaded: 09/13/2008).
---------------------------------------------------------------------------
    Even without new refineries, existing refineries have invested to 
expand capacity. The distribution of historical investment rates is 
shown in figure 8. While the mean investment has been 1.3 percent per 
year, the median is zero as plants tend to make very infrequent 
investments. Even restricting the sample to non-zero changes as shown 
in the graph, investments tend to be small, with almost 85 percent of 
the non-zero changes less than 10 percent. Though over half of the 
plant-year observations in my sample show no change in atmospheric 
distillation capacity, there is some investment in either upstream or 
downstream units in over 63 percent of the observations.
2.2 Profitability (Crack Spreads)*
---------------------------------------------------------------------------
    * All equations have been retained in committee files.
---------------------------------------------------------------------------
    Although oil refining has historically been an industry plagued by 
thin profit margins, oil producers typically see larger profits when 
crude oil prices arc low and/or product demand is relatively high. One 
simple measure of the profit margin at a refinery is the ``crack 
spread.'' For every barrel of crude oil the refinery uses, 
technological constraint.s require that about half of it goes into 
gasoline production and about a quarter into distillate. So the crack 
spread, expressed in dollars per barrel, is calculated as:
    The crack spread for three stats are shown in figure 9. Data arc 
from EIA and arc based on the first purchase price of crude oil, 
gasoline and distillate in each state.\17\ The crack spread fluctuates 
quite a bit from month to month, generally peaking in the summer months 
of each year. Refineries in each state may be using very different 
crude oils (for example Brent on the East Coast, WTI in the Midwest, 
and Alaskan North Slope on the West Coast). Though the crack spreads 
shown tend to move together, the levels vary and refineries in one area 
of the country may have better price spreads than in another area and 
these relationships change over time. Some argue that based on this 
measure of profitability, it is surprising that more refiners have not 
overcome the setup costs and entered this industry.
---------------------------------------------------------------------------
    \17\ See: http://www.eia.gov/dnav/pet__ pet__pri__dfpl__m__.htm and 
http://www.eia.gov/dnav/pet/
pet__pri__refoth__a__epm0__pwg__dpgal__m.htm
---------------------------------------------------------------------------
    Aside from the recession of 2008, while total refining capacity has 
risen in the past 10 years, it has not kept up with demand growth. 
Capacity of oil refiners has increased by 10 percent in the past 10 
years, while demand for gasoline has increased about 17 percent. The 
gap has been filled by new requirements that gasoline be blended with 
ethanol and to some degree, growing imports. However, new regulations 
requiring the shift from MTBE\18\ oxygenates to ethanol poses a problem 
for this segment of supply because foreign refiners have not invested 
in the facilities to produce ethanol blended gasoline. Even with excess 
capacity, at certain times of the year supply alternatives can be 
limited so even a minor supply disruption (or a major one like 
Hurricane Katrina) can have a large price impact.\19\
---------------------------------------------------------------------------
    \18\ Methyl Tertiary Butyl Ether.
    \19\ Following Hurricane Katrina on 9/23/05, capacity fell by 5 
MBbl/Day. This represented a full one third of US refining capacity. 
Inventories are also limited as there is only about 20-25 days worth of 
gasoline in storage at any time.
---------------------------------------------------------------------------
2.3 Refinery Maintenance and Outages
    An oil refinery is a complex operation that requires frequent 
maintenance, ranging from small repairs to major overhauls.\20\ The 
regular maintenance episodes tend to be short and have minimal impact 
on production as they are strategically scheduled for low demand 
periods. Unplanned outages, by definition, can take place at any time 
and can have a major impact on production capability. The EIA divides 
refinery outages into four classes, summarized in table 2.3.**
---------------------------------------------------------------------------
    \20\ Refinery maintenance is crucial not only for production 
sustainability, but also for the safety of the plant . A 2005 fire at 
BP's Texas City refinery killed 15 workers and injured over 100 more.
    ** All tables have been retained in committee files.
---------------------------------------------------------------------------
     Planned turn-arounds are major refinery overhauls, while planned 
shutdowns bridge the gap between turn-arounds. Unplanned shutdowns 
involve unexpected issues that may allow for some strategic planning of 
the downtime, but often may force a refinery to reduce production sub-
optimally. Finally, emergency shutdowns are those that cause an 
immediate plant breakdown like a refinery fire.
    Organization for planned turn-arounds typically start years in 
advance, and cost millions of dollars Lo implement, in addition to the 
revenue lost from suspending production. Due to the hiring of outside 
personnel, major refineries often have to plan these turnarounds at 
different times because of the shortage of skilled labor to implement 
them. Given the typical seasonal variation in product demand, the ideal 
periods for maintenance are the first and third quarter of the year, 
though in some northern refineries, cold winter weather forces shifts 
in planned downtimes. Figure 10 shows the planned and unplanned outages 
over time for all US plants. Clearly seen in the figure is the increase 
in unplanned outages following the hurricanes in 2005 and the increase 
in planned outages in 2009 as refiners went offline for maintenance as 
demand fell during the recession.
    Even though refineries consist of several components, such as 
distillation columns, reformers and cracking units, these components 
are dependent on one another so a breakdown of any one component can 
affect the production capability of the entire refinery. Downstream 
units include hydrocrackcrs, reformers, fluid catalytic cracking (FCC) 
units, alkylation units, and coking units. They are responsible for 
breaking down hydrocarbons into more valuable products and removing 
impurities such as sulfur. For example, in a typical refinery, only 5 
percent of gasoline is produced from the primary distillation process; 
the rest comes hydrocrackers (5 percent), reformers (30 percent), FCC 
and alkylation units (50 percent), and coking units (10 percent). Not 
all refineries have all of these components, so such refineries are 
even more affected when one component goes down (EIA (2007)).
    Figure 11 shows the percent of capacity offline by year and for 
various refining units. Though the percentages tend to move roughly 
together, certain units are more affected in some years (e.g., most 
catalytic hydrocracking capacity is located along the Gulf Coast so was 
particularly effected by the hurricanes in 2005). Since 2005, typically 
5-8 percent of each unit's capacity is offline in a given year for 
either planned maintenance or unplanned outages.
    At the PADD level, EIA reports that in the 1999-2005 period, 
refineries experienced reductions in mont hly gasoline and distillate 
production of up to 35 percent due to outages. At the monthly 
frequency, there is little effect of outages on product prices. This is 
primarily because most (planned) outages occur during the low-demand 
months when markets are not tight; most outages last less than a month; 
and the availability of imports, increased production from other 
refineries, and inventories provide a cushion to supply. However, 
unplanned outages, like those caused by a hurricane, still affect may 
have significant effects on the downstream prices and profitability of 
all refineries.
    Overall, the oil refining industry features several economic 
puzzles, some of which I explore in this paper. While the industry is 
relatively competitive, refiners at times can earn significant profits, 
as measured by the crack-spread. However, entrants have yet to overcome 
the regulations and costs of setting up a new plant and existing firms 
have been cautious in their expansion. As a result, plants may run at 
high rates of utilization, which leads to instability in the face of 
unexpected capacity disruptions. These outages can impact both product 
prices and the investment decisions of refiners.
3 Data
    I collect outage data on all refineries from 2001 2010 from 
Petrocast (Industrial Info Resources) . Outage data are available by 
plant and unit type (atmospheric distillation, FCC, hydrocrackers, 
reformer, and thermal crackers) and planned and unplanned outages are 
reported separately. I observe the length of the outage (in days) and 
the number of barrels that were offline.\21\ Descriptive statistics on 
the outages data are shown in table 2. Of the 13,696 plant-year-month 
observations in the data, 3,544 contain some type of outage. The 
average monthly atmospheric distillation outage is around 203,000 
barrels.
---------------------------------------------------------------------------
    \21\ There are other potentially interesting dimensions to the data 
that I plan to exploit in future work. I mention a few in section 5.
---------------------------------------------------------------------------
    I match the outage data with investment data that is publicly 
available from the US Energy Information Administration (EIA). The data 
reflect the current atmospheric distillation capacity of the plant, but 
also the capacities of the downstream units mentioned above. Capacity 
data is available at an annual level and descriptive statics for 2010 
are shown in table 3. Almost all plants in the database have 
atmospheric distillation and reforming capacity and most have catalytic 
cracking units.\22\ Investments in physical capacity are infrequent 
given the high costs of taking units offline while the changes are 
made. Therefore annual data is appropriate for measuring these changes, 
however smaller increases in capacity throughput (known as ``capacity 
creep,) may occur throughout the year. Since EIA and Petrocast do not 
share a common plant identifier, I manually match plants between the 
two datasets based on their name and location, which results in a 
database containing 107 plants and representing about 92 percent of 
total US refining capacity.
---------------------------------------------------------------------------
    \22\ 0f the 107 plants in the database, 103 are active in 2010.
---------------------------------------------------------------------------
    Finally, I collect refiner wholesale prices of gasoline, distillate 
(diesel fuel), and first purchase prices of crude oil from which I 
create a simple 3-2-1 crack spread described in section 2.\23\ Both the 
crude oil and product prices are usually available at the state-level 
so all refineries in a given state are matched to the same set of 
prices. For states that EIA does not report a crude oil price, I use 
the corresponding PADD price. In some regressions below, I also use 
PADD-level gasoline and distillate prices that are averages of the 
state-level prices. Gasoline and distillate stocks (available at the 
PADD level) and utilization rates (available at the PADD-district 
level) arc also matched to the data.\24\ Descriptive statistics on 
utilization rates, prices, and refinery stocks are shown in table 4. 
Utilization rates during my sample average about 89 percent of 
atmospheric distillation capacity and crude prices average 58 dollars 
per barrel (though peak around $134 in 2008). The crack spread 
experiencs considerable variability over the sample period, ranging 
from 20 cents up to almost one dollar per gallon.
---------------------------------------------------------------------------
    \23\ EIA defines a first-purchase price as ``An equity (not 
custody) transaction involving an arms-length transfer of ownership of 
crude oil associated with the physical removal of the crude oil from a 
property (lease) for the first time. A first purchase normally occurs 
at the time and place of ownership transfer where the crude oil volume 
sold is measured and recorded on a run ticket or other similar physical 
evidence of purchase.''
    \24\ Data. are available here: capacity: http://www.eia.gov/
petroleum/refinerycapacity/product prices: http://www.eia.gov/dnav/pet/
pe__pri__refoth__dcu__nus__m.htm crude prices: http://www.eia.gov/
dnavj/pet/pet__pri__dfpl____m.htm utilization Rates: http://
www.eia.gov/dnav/pet/pet__pnp__unc__dcu__nus__m.htm stock: http://
www.eia.gov/dnav/pet/pet__stoc__ wstk__a__epmO__sae__mbbl__m.htm
---------------------------------------------------------------------------
4 Empirical Specifications and Results
    In the following section, I outline my empirical specifications and 
results regarding the relationships between oil refinery outages, 
profitability, utilization and investment. I first consider planned 
outages and how they are affected by profitability and time-ofyear 
effects. Then I move to unplanned outages and consider how the 
intensity at which a plant is running and the time since the last 
maintenance episode affect the likelihood of future outages. Once I 
understand the causes of outages, I then turn to their effect on 
prices, specifically considering how the current tightness of the 
market as measured by utilization rates and product stocks affect the 
impact of outages on prices. The last empirical specification brings 
everything together to determine how planned and unplanned outages, 
utilization rates, the crack spreads affect the future investment 
decisions of refiners.
4.1 Planned Outages
    In this subsection, I try to answer the question, ``Do refiners 
generally take planned downtime for maintenance when profit margins are 
low and do they delay taking their plants offline when margins are 
high?'' To answer this question, I estimate the following regression:

    Planned outages by refinery j in month m are regressed on the crack 
spread (available at the state level) and month fixed effects.\25\ I 
estimate a simple probit regression predicting the probability of an 
outage, running separate models for all outages, atmospheric 
distillation outages, catalytic cracking outages, and catalytic 
hydrocracking outages. Controlling for month effects is crucial because 
it is well know that plants take annual maintenance in the low-demand 
periods (usually early spring and again in the fall) and my goal is to 
estimate the effect of the crack spread changing throughout the year.
---------------------------------------------------------------------------
    \25\ Including the crack spread in the previous month produces 
similar results.
---------------------------------------------------------------------------
    Results of this specification are shown in table 5. The cocfiicient 
on the crack spread is negative and significant when considering the 
probability of any planned outage meaning that refiners to tend to hold 
off planned outages when profitability is favorable. I also consider 
planned atmospheric, catalytic cracking and hydrocracking outages 
separately, and the results generally hold for all but the last type of 
outage. The crack spread is clearly a very rough measure of refinery 
profitability so other prices and constraints may be affecting the 
result for the hydrocracking specification.
    Interpreting the magnitude of these coefficients is easier by 
considering the marginal effects. In figure 12, I plot the marginal 
effects by the month of the year. The graph shows the strong 
seasonality in planned outages, peaking in May and again in October. I 
evaluate these effects at three different levels of the crack spread: 
the lOth, 50th and 90th percentiles. The higher crack spreads are 
associated with a lower predicted probability of a planned outage. 
Figure 13 shows the marginal effects of varying the crack spread for 
three different months of the year. The predicted probability of a 
planned outage ranges from over 0.3 when crack spread is low to less 
than 0.05 when tho crack spread is relatively high.
4.2 Unplanned Outages
    Next, I move on to the question, ``How are unplanned outages 
affected by utilization rates and the time since the last plant turn-
around?'' Unfortunately, utilization rates are only measured at the 
PADD-district level so are an imperfect proxy for the production 
intensity of any given plant. They also measure only the atmospheric 
distillation utilization, which is an important unit at a refinery, but 
only one of many that is involved in the production process. Therefore, 
I estimate the following regression:

    Again, a probit model is estimated predicting the probability of an 
unplanned outage at refinery j in month m. The variable TSLTA measures 
the time since the last turnaround in months. I calculate this time 
using the last planned outage of the atmospheric distillation unit at a 
given plant. Turn-arounds generally involve complete plant shut downs 
so planned atmospheric distillat ion outages are a good indicator of 
turn-arounds.\26\ Again, month fixed effects are included because, 
although unplanned outages are more random than planned outages, 
weather (such as, late summer hurricanes) can introduce some 
seasonality into unplanned outages.
---------------------------------------------------------------------------
    \26\ For robustness, I have also used both the time since the last 
planned FCC and hydrocrack outage and the results are similar.
---------------------------------------------------------------------------
    Results of this specification are presented in table 6. While the 
TSLTA variable is consistently positive and significant as expected, 
the utilization rate is estimated to be negative and significant in all 
specifications. This is likely because the rate is measured at the 
PADD-district level and a large outage that affects all plants in a 
district will lead to large outages contemporaneous with low 
utilization rates where the outages may last more than a month, driving 
the negative relationship. In future work, I will consider only 
isolated outages, where one plant experiences an unplanned outage while 
its neighbors (in the same district) are fully operational.
    Again, the magnitude of the effects are better seen with a graph of 
the marginal effects. Figure 14 shows the probability of an unplanned 
outage as a function of the time since the last planned plant turn-
around. This effect is increasing though lower for higher utilization 
rates, ranging from about 0.10 for plants that have recently performed 
maintenance to 0.25 for plants that have not experienced a planned 
turn-around in 8-9 years.\27\
---------------------------------------------------------------------------
    \27\ The data are not rich enough to show planned turn-arounds that 
are spurred on by unplanned outages, but for robustness I calculate the 
TSLTA variable based on the time since the last outage (of any type) 
and the results are similar. Note, the mean and median time since the 
last planned atmospheric distillation outage are 17.5 and 13 months 
respectively.
---------------------------------------------------------------------------
4.3 Product Prices
    The last two subsections showed that planned outages tend to occur 
during the spring and fall and during times of relatively low margins 
as measured by the crack spread. The amount of time since the last 
plant turn-around is positively associated with future unplanned 
outages. But the question then becomes, ``Do these outages have an 
effect on prices?'' An outage that occurs during a time when 
inventories are relatively high and/or nearby utilization rates are 
low, should have less of an effect on output prices than when the 
market is relatively tight. Therefore, I estimate the following 
regression equation using OLS:

    Since wholesale prices arc generally determined by markets that are 
larger than individual states (due to pipelines, imports, etc), I run 
this regression on gasoline prices in PADD p and month m. The 
independent variables include the crude oil price, aggregate outages in 
the PADD, and gasoline stocks. Month and PADD fixed effects are also 
included to account for seasonality and any geographic variation in the 
level of prices unrelated to outages. I also run the model on 
distillate prices and stocks.
    Table 7 presents results of four specifications run on gasoline and 
distillate prices using either atmospheric distillation outages or FCC 
(fluid catalytic cracking) outages. In each regression, I include 
planned and unplanned outages separately to determine if product prices 
are better able to absorb planned outages. The results clearly show 
that the variation in the crude oil price is the primary driver of the 
level of gasoline and distillate prices with coefficients very close to 
one. The gasoline price regressions also show that unplanned 
atmospheric and FCC outages have a positive and significant effect on 
prices, and the effect is about twice as large as the effect of planned 
outages (the latter coefficients are not statistically significant). 
Gasoline stocks have an expected negative and significant effect on 
prices.
    The distillate price regressions show that planned atmospheric 
distillation outages have an effect on prices and FCC outages show no 
significant effect. The FCC unit is relatively more important for 
ga..c;oline production so this result is not unexpected though it is 
surprising that unplanned atmospheric outages show no significant 
effect. To better account for the fact that a refinery is composed of 
many refining units and each is more or less important for producing 
gasoline and distillate, I run two regressions of prices on the outages 
of individual refining units. These results are presented in table 8. 
The results show that atmospheric distillation and catalytic cracking 
have the largest positive effect on gasoline prices and thermal 
cracking is also important for distillate prices. In both 
specifications, the coefficient on reformer outages comes out negative 
and significant. This may be because reformers are used to increase the 
octane of gasoline so if the reformer goes down, plants will end up 
producing more (lower octane) regular grade gasoline, depressing the 
price.\28\
---------------------------------------------------------------------------
    \28\ Explaining the coefficient on reformer outages in the 
distillate regression is harder, but it may have something to do with 
refiners increasing their distillate yield (perhaps by adjusting the 
yield on their hydrocracker) driving down the price of distillate.
---------------------------------------------------------------------------
    Finally, in figure 15, I show the estimated price effect of 
atmospheric distillation outages, where I run separate regressions for 
various levels of the utilization rate.\29\ 95 percent confidence 
limits on the estimated coefficient arc also shown on the graph. The 
estimates are generally increasing in the prevailing utilization rate 
indicating that outages that occur during periods of high utilization 
rates have more of an effect on prices then when utilization rates are 
low. The economic importance of these results can be seen by estimating 
the predicted effect on prices for typical outages seen in the real 
world. For example, at 90 percent utilization rates, if an average US 
refinery went offline, the model predicts that gasoline prices would 
rise by 7.3 cents per gallon. When utilization rates are closer to 85 
percent (the average in 2011), the same outage would cause a predicted 
increase in gasoline prices of 2.4 cents per gallon.\30\
---------------------------------------------------------------------------
    \29\ I run separate regression for months when the utilization rate 
in the PADD-district was between 72.5 percent and 77.5 percent and then 
between 77.5 percent and 82.5 percent, etc.
    \30\ The first estimate is found by multiplying the predieted 
effect (1.5 cpg) by the size of an average refinery (161,000 bpd) 
divided by 1 percent of an average PADD's total capacity (33,227 bpd).
---------------------------------------------------------------------------
4.4 Investment
    The last set of regressions consider how planned and unplanned 
outages, utilization rates, and profitability affect the future 
investment behavior of refiners. I expect that refiners would be more 
likely to invest in additional capacity following years with high crack 
spreads, high utilization rates, and large unplanned outages. I 
estimate the following regression:

    Investment in capacity by plant j in year y is regressed on last 
year's average crack spread and utilization rate.\31\ I include plant 
and year fixed effects in some of the specifications. Year fixed 
effects are important to control for the interest rate that may be 
changing over time and affecting a refiner's investment decision. 
Results are shown in table 9. The three specifications presented have 
no fixed effects, year fixed effects, and year and plant fixed effects 
respectfully. With a complete set of controls, the crack spread and 
utilization rate do come out positive as expected though both are 
insignificant. Outages, especially planned outages, are positively 
associated with investment, which may result from refiners taking 
planned outages to prepare their plants for future investments in 
capacity.
---------------------------------------------------------------------------
    \31\ The crack spread is based on state-level prices and the 
utilization rate is the average annual utilization rate in the 
corresponding refining district.
---------------------------------------------------------------------------
    I also consider downstream investment in capacity as shown in table 
10. Estimated coefficients on crack spreads and utilization rates are 
mixed. Unplanned outages of FCC units have a positive and significant 
effect on FCC investment and planned thermal cracking outages are also 
associated with more investment in thermal cracking capacity. However, 
other types of outages on the various refining units do not show a 
consistent or significant effect.
5 Conclusion
    The focus of this paper was the effect of refinery outages on 
product prices and investment. It is well known that crude oil prices 
are the primary driver of gasoline and other petroleum product prices. 
However, I have shown that outages at refineries, both planned and 
unplanned, can have important implications for the level of prices and 
the future investment decisions of refiners. Refineries are extremely 
complicated operations and understanding how their operations and 
outages affect the price we pay for gasoline is difficult to determine. 
However, with detailed data on both the capacities and outages of 
individual refining units, it is possible to show that depending on the 
current market conditions (prevailing utilization rates and crack 
spread), refiner behavior can have an economically significant effect 
on product prices.
    As expected, planned outages tend to occur during the low-demand 
periods and when crack spreads are less favorable for production, while 
unplanned outages are more likely to occur when a refiner has put off 
performing planned maintenance on the plant. Product prices are 
positively associated with outages, though the effect varies with the 
type of outage and the level of tightness in the market as measured by 
the utilization rate and product stocks. Finally, I showed that 
investment in certain refining units is higher when outages to those 
units have recently occurred, but the effects are weak suggesting that 
there are other considerations affecting a refiner's decision to invest 
in capacity. These likely include long-term forecasts of product 
demand, crude oil supply and prices, and a regulatory environment that 
is constantly changing and affecting a plant's profitability.
    There are several directions for future work exploiting a few of 
the unique features of the dataset. The outage data includes 
information about planned outages that have been rescheduled or 
postponed. This may allow me to better estimate how refiners respond to 
economic conditions as they determine when to perform their planned 
maintenance. For more recent data (2009 and 2010) , I also observe the 
reason for the outage (planned turn-around, economic conditions, etc). 
A more challenging project involves gaining a better understanding of 
the motivations for investment (or divestment) in the refining industry 
since gasoline and other refined petroleum products are essential to 
the US economy and domestic refineries supply almost all of those 
products.
A The Distillation Process
    Since the various components of crude oil have different boiling 
points, a refinery's essential task is to boil the crude oil and 
separate it into the more valuable components. Figure A.1 displays a 
simplified diagram of a typical refinery's operations. The first and 
most important step in the refining process is called fractional 
distillation. The steps of fractional distillation are as follows:

          1. Heat the crude oil with high pressure steam to 1,112 
        degrees fahrenheit.
          2. As the mixture boils, vapor forms which rises through the 
        fractional distillation column passing through trays which have 
        holes that allow the vapor to pass through.
          3. As the varpor rises, it cools and eventually reaches its 
        boiling point at which time it condenses on one of the trays.
          4. The substances with the lowest boiling point (such as 
        gasoline) will condense near the top of the distillation 
        column.

    While some gasoline is produced from pure distillation, refineries 
normally employ several downstream processes to increase the yield of 
high valued products by removing impurities such as sulfur. Cracking is 
the process of breaking down large hydrocarbons into smaller molecules 
through heating and/or adding a catalyst. Cracking was first used in 
1913 and thus changed the problem of the refiner from choosing how much 
crude oil to distill into choosing an appropriate mix of products 
(within some range). Refineries practice two main types of cracking:

   Catalytic cracking: a medium conversion process which 
        increases the gasoline yield to 45 percent (and the total yield 
        to 104 percent).
   Coking/residual construction- a high conversion process 
        which increases the gasoline yield to 55 percent (and the total 
        yield 108 percent).

    The challenge of choosing the right input and output mix given the 
available technology creates a massive linear programming problem.
B Crude Oil Quality
    Crude oil is a flammable black liquid comprised primarily of 
hydrocarbons and other organic compounds. The three largest oil 
producing countries are Saudi Arabia, Russia and the United States.\32\ 
Crude oil is the most important input into refineries and this raw 
material can vary in its ability to produce refined products like 
gasoline. The two main characteristics of crude that determine its 
quality are American Petroleum Institute (API) gravity and sulfur 
content. The former is a measure (on an arbitrary scale) of the density 
of a petroleum liquid relative to water.\33\ Table B.l summarizes these 
characteristics and includes some common crude types and their gasoline 
yield from the initial distillation process.
---------------------------------------------------------------------------
    \32\ Production in this sense refers to the quantity extracted from 
a country's endowment.
    \33\ Technically, API gravity = (141.5/ specific gravity of crude 
at 60 F)--131.5. Water has an API gravity of 10 .
---------------------------------------------------------------------------
    Worldwide, light/sweet crude is the most expensive and accounts for 
35 percent of consumption. Medium/sour is less expensive and accounts 
for 50 percent of consumption while heavy/sour is the least costly and 
accounts for 15 percent. Figure B.l show how the average crude oil used 
by US refiners is becoming heavier and more sour over time though 
leveling off toward the latter part of the 2000s. This means that the 
production costs of a gallon of gasoline are changing as refineries 
must invest in more sophisticated technology in order to process lower 
quality crude oil.
    Since crude oil by itself has very little value to any industry, 
the price of a barrel of oil reflects the net value of the downstream 
products that can be created from it. The two major sources of 
movements in the crude oil price are upstream supply shocks (e.g., due 
to OPEC's production quotas, internat ional tensions, and hurricanes 
affecting oil rigs in the Gulf of Mexico) and downstream demand shocks 
(mainly due to consumer's demand for refined products). The other 
source often sited by industry experts are refinery inventories of 
crude oil. Maintaining stocks of crude oil allow the refinery to 
respond quickly to downstream shocks like an unexpectedly cold winter 
increasing the demand for heating oil.
    Within the various types of crude oil, the prices of each quality 
respond differently to shocks. The ((light/heavy'' differential is one 
measure that indicates the benefit a refiner can achieve by investing 
in sophisticated equipment to process heavier crude oil into highly-
valued refined products. The differential has varied significantly over 
the last 10 years from 3 dollars per barrel to almost 20 dollars per 
barrel. An oil refinery faces a unique decision when making its 
production choice, one that provides for both flexibility and 
complexity. One one hand, consumers do not care about the type of crude 
oil, oxygenates, or distillation process used to make, for example, the 
gasoline they put in their cars. They just want their car to run well. 
While this would appear to make a refiner's problem easier, choosing 
their heterogeneous inputs, such as crude oil, satisfying federal, 
state and city environmental regulations, and all while maximizing 
profits, makes for an enormously complex optimization.
C Other Tables and Figures*

    Note: All equations have been retained in committee files.
                                 ______
                                 
 Statement of Robert F. McCullough, Jr., Managing Partner, McCullough 
                         Research, Portland, OR
    This report reviews the recent shift in the gasoline market in 
California. A careful re-view of the limited information available 
indicates that a relatively minor plant problem at ExxonMobil's 
Torrance refinery was to blame for the almost instantaneous increase in 
wholesale prices in October 2012. Yet there is evidence that the 
Torrance refinery problems were overstated and that speculation in 
gasoline began before the difficulties at Torrance were known and 
understood in the market. An article indicating that all of the majors 
took part in the speculative trading raises the question of collusion, 
since it would be unlikely that ExxonMobil, the owner of Torrance, 
would inform its competitors of operating problems prior to informing 
regulators and the media.
    Since May 2012, retail prices on the West Coast have diverged 
significantly from fun-damentals. As a simple measure, the correlation 
of California retail prices and world oil prices was 90 percent, but in 
May the correlation had fallen to less than 2 percent. A traditional 
statistical study would be unable to reject the hypothesis that 
California retail prices are independent of world oil prices.
    The chart* above draws a line (shown in red) through gasoline 
prices since April 2012. The shallow slope of the line indicates the 
marginal impact world oil prices have had upon California consumers 
since April 2012. Market data until May 2012 is shown in white. The 
slope of the white line reflects the traditional relationship between 
oil prices and gasoline prices. The quality of the statistical 
relationship is shown by the R2. A perfect relationship 
between two variables has an R2 of 1.00. The R2 
of two completely unrelated variables is 0.00. The R2 value 
of 0.904 indicates that before May 2012, the price of gasoline could be 
well explained by the price of crude oil. However, since May, the 
R2 value of .0185 suggests that there is almost no 
relationship between oil prices and gasoline prices in California.
---------------------------------------------------------------------------
    * All charts have been retained in committee files.
---------------------------------------------------------------------------
    The industry's response to studies questioning this abrupt change 
is generally uncon-vincing. The May spike was widely blamed on the 
Cherry Point fire in February. The October spike was largely blamed on 
the outage at Torrance, but the Richmond explosion--two months 
earlier--was also blamed. No explanation has been forthcoming on why 
price spikes would be delayed by several months instead of occurring 
immediately.
    Gasoline markets in the U.S. traditionally track world oil prices. 
Additional critical information concerns the level of production and 
the size of gasoline inventories. These well-known factors are 
available on a weekly basis from the Energy Information 
Administration.\1\ Some states provide more detailed information. The 
California En-ergy Commission publishes the Weekly Fuels Watch Report, 
which offers detailed data on gasoline inventories and production.\2\
---------------------------------------------------------------------------
    \1\ http://www.eia.gov/petroleum/supply/weekly/
    \2\ http://energyalmanac.ca.gov/petroleum/fuels--watch/index.php
---------------------------------------------------------------------------
    It is often useful to ``backcast'' economic events, in this case 
examining a forecasting model to see how well the explanatory 
variables--oil prices, production, inventory, and demand--explain 
gasoline prices. The backcast of gasoline prices in California 
identifies two periods, May and October 2012, as periods when prices 
diverged significantly from fundamentals.
    The following chart* compares the prices that would have resulted 
from the forecast with the actual prices over this period.
    The May 2012 price spike reflects a period when gas prices 
increased while oil prices declined. The October spike is interesting 
since the price increase was more dramatic and took place over a very 
short time period. In fact, the rate of price increase over the October 
2012 period is the highest observed between 2000 and the present, even 
after correcting for inflation.
    As shown in the chart above, the fundamentals in October 2012 would 
not have indicated a retail price increase. October gasoline sales in 
California showed a small increase over September 2012 and the price of 
crude in October showed a small decline over the period of the price 
spike. In fact, inventory levels actually increased during the spike--
contradicting the shortage theory.
    The California Energy Commission's alternative explanation of 
problems at ExxonMobil's Torrance refinery appears to have some merit, 
although the timing of the price spike is highly suspect\3\ As 
mentioned, it appears that the price began spiking before the ``power 
failure'' at the Torrance refinery was publicly announced.
---------------------------------------------------------------------------
    \3\ Schremp, Gordon. ``California Refineries: System Reliability, 
Gas Prices and the Economy.'' November 15, 2012.
---------------------------------------------------------------------------
    Gordon Schremp, the California Energy Commission's witness at the 
November 15, 2012 hearing held by the California Senate, provided the 
following chart*:
    This chart suggests that the steep retail and wholesale price 
increases incurred imme-diately after the ExxonMobil problems at 
Torrance. Mr. Schremp argued that later data releases from the 
California Energy Commission showed stable production and increasing 
inventories which mitigated the perception of shortage and gradually 
re-duced prices.\4\
---------------------------------------------------------------------------
    \4\ The October 5, 2012 CEC Weekly Fuels Watch Report indicated 
that inventories had actually increased from the previous week. http://
energyalmanac.ca.gov/petroleum/fuelswatch/output.php
---------------------------------------------------------------------------
    Announcement effects such as the California Energy Commission's 
alternative explanation generally are difficult to prove. The valuable 
information provided in the CEC's weekly reports is likely to affect 
market perceptions. Unfortunately, the data also reflects the 
fundamentals in the market, meaning that it is statistically very 
difficult to determine whether it was the CEC's report or the market 
fundamentals that affected prices.
    The timing of the announcement of a power failure at ExxonMobil's 
Torrance refinery is another matter. The initial event, a frequency 
fluctuation on SCE's system, was extensively reported in the media. One 
reporter even referenced the ``power bump, which was felt in the Daily 
Breeze offices on Hawthorne Boulevard, knocking out electricity for a 
split-second.''\5\
---------------------------------------------------------------------------
    \5\ Altman, Larry. ``Torrance ExxonMobil refinery flare erupts 
against morning sky.'' Daily Breeze, October 1, 2012
---------------------------------------------------------------------------
    ExxonMobil filed notifications with the South Coast Air Quality 
Management District (SCAQMD) at 8:20 a.m. and the California Emergency 
Management Agency at 8:28 a.m. Such notifications are not very 
informative other than noting the date and time of the event. Reuters 
reported on the SCAQMD flare notification at 8:21 a.m.\6\ The first in-
depth article describing the power outage was released by Dow Jones 
Newswire at 8:55 a.m.:

    \6\ Unspecified Breakdown Leads to Flaring at ExxonMobil's 149,500 
b/d Torrance, California Refinery.'' Reuters, 11:21 a.m. EDT., October 
1, 2012. ``ExxonMobil Corp. reported unplanned flaring due to an 
unspecified breakdown at its Torrance refinery Monday morning, 
according to a filing with the South Coast Air Quality Management 
District,''

          ExxonMobil Corp. (XOM) on Monday said flaring could be 
        visible throughout the day at its oil refinery in Torrance, 
        Calif., due to equipment breakdown.
          The company reported the incident to the South Coast Air 
        Quality Management District soon after it occurred at 10:20 
        a.m. EDT on Monday. The report said the unplanned flaring event 
        is expected to end by midnight, but didn't say what equipment 
        was involved in the event.\7\
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    \7\ Marton-Vitale, Rose. ``ExxonMobil Reports Equipment Breakdown, 
Flaring at California Refinery.'' DowJones Newswire, October 1, 2012.

    This story was unlikely to lead to panic buying in California 
markets, although an article published 45 minutes later gave 
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significantly more information:

          REFINERY NEWS--L.A. CARBOB DIFFERENTIAL JUMPS OVER 35 CENTS 
        ON TORRANCE UPSET

    Houston (Platts)--1Oct2012/1240 pm EDT/1640 GMT Refinery: Tor-
rance, California Owner: ExxonMobil Overall capacity (b/d): 149,500 
Units affected: N/A Units capacity (b/d): N/A Duration: Emissions 
window 7:20 a.m. PDT to 11:59 p.m. PDT Monday Notes: The Los An-geles 
CARBOB differential spiked more than 35 cents Monday after a power 
failure at the refinery, sources said.
    The main California-specific grade of gasoline was heard done at 
NYMEX November RBOB contract plus 58 cents and plus 65 cents/gal early, 
and then bid to plus 85 cents/gal, with offers at $1/gal heard. Platts 
assessed the differential at plus 50 cents/gal on Friday.
    The differential increase came after reports of the breakdown at 
the gas-oline-centric plant that sources said suffered a power failure. 
An Exx-onMobil spokeswoman did not immediately respond for comment.
    The underlying November RBOB futures contract was trading at 
$2.8912/gal at noon EDT. Source: Market sources\8\
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    \8\ ``Refinery News: L.A. CARBOB Differential Jumps Over 35 Cents 
on Torrance Upset.'' Platts Commodity News, October 1, 2012.

    Translated into everyday English, this article says that prices in 
wholesale California markets had spiked $.35/gallon within 45 minutes 
of the first substantive coverage by the media and 80 minutes after 
ExxonMobil reported the event to SCAQMD.
    It is clear that the reporting of the flaring to SCAQMD by Exxon 
did not cause, or even set in motion events that would cause prices to 
increase by $.35/gallon. During 2012, the Torrance facility reported 27 
other flaring events, none of which set off price increases anywhere 
near the scale of those seen on October 1st.\9\
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    \9\ SCAQMD flare archives at http://www.aqmd.gov/listserver/email/
exxonmobiltorrance.arc/right.htm

    Why was this flaring report different, and what happened during 
this period that raised the wholesale price so significantly? From the 
official notifications and the thin media coverage, no outsider would 
be able to conclude that a major event had occurred at Torrance. As we 
discuss below, press coverage and SCAQMD emissions records suggest that 
production continued during this time period.
    One media article described the majors jumping into the market on 
October 1:

          ``Today, gasoline was like a bat out of hell,'' said the 
        trader who asked not to be identified. ``All the majors came 
        out and bought. This morning it was all bad news from the get-
        go.''\10\
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    \10\ ``US West Coast Products--Gasoline jumps on refinery outage.'' 
Reuters News, October 1, 2012.

    The morning in question was roughly contemporaneous with the 
reports above since the article's author and, presumably, the 
unidentified trader, were in Houston.
    The wholesale prices increased in California over three days. On 
Monday October 1st, there was a significant price increase of over 
$.20/gallon.\11\ On Tuesday, prices in-creased $.14/gallon and on 
Wednesday, October 3rd, prices increased $.45/gallon.
---------------------------------------------------------------------------
    \11\ Different reports give different values for the price 
increases. The OPIS data represents an end-of-day survey. Press reports 
often cite anecdotal evidence after discussions with individual 
traders.
---------------------------------------------------------------------------
    The scale of the problem at Torrance is still doubtful. On Monday, 
ExxonMobil told the media that there had been an external power outage:

          ``The ExxonMobil Torrance Refinery experienced an unplanned 
        flaring event due to an external power interruption and 
        notified the Torrance Fire Department,'' spokeswoman Gesuina 
        Paras said in an email. ``The cause is under 
        investigation.''\12\
---------------------------------------------------------------------------
    \12\ ``Refinery News Update: ExxonMobil reports breakdown at 
Torrance, California.'' Platts Commodity News, Oc-tober 1, 2012.

    A spokesperson for Southern California Edison described the 
---------------------------------------------------------------------------
situation differently:

          ``But SCE says the only electricity incident that morning was 
        a `flickering light-type condition,' according to Steve Conroy, 
        a Southern California Edison spokesman.
          Conroy describes it like a hiccup--lasting less than a second 
        according to residential customers in the area. He says there 
        was no outage at the substation.
          `An outage just means you've lost service. Your power goes 
        off. We're not aware of that happening in the community to 
        other customers,' said Conroy. `How that condition affected the 
        refinery is not known to us at this point in time.'''\13\
---------------------------------------------------------------------------
    \13\ ``ExxonMobil Torrance refinery investigated for effect on 
spiking California gas prices.'' Los Angeles News, October 12, 2012.

    Our previous reports on the gasoline price spikes relied on 
emissions data for individual refineries supplied by California's Air 
Quality Management districts.\14\ We returned to this source to better 
understand how the Torrance refinery was affected by this flaring event 
and the resulting impact on the October 2012 price spike.
---------------------------------------------------------------------------
    \14\ ``May and October 2012 Gasoline Price Spikes on the West 
Coast.'' November 15, 2012, http://www.mre-search.com/pdfs/489.pdf
---------------------------------------------------------------------------
    The evidence from the nitrogen oxide (NOX) reports filed 
by ExxonMobil at SCAQMD tends to support a more moderate view of the 
incident. NOX emissions from the refinery's cogeneration 
facility dropped to 30 percent of Sunday's levels. This would indicate 
that the co-generation unit had gone off-line at 7:30 a.m. on October 
1.
    Cogeneration equipment is used to produce steam for operations 
elsewhere at a refin-ery. Torrance has three small cogeneration 
turbines that are integrated with the facility. A temporary ``flicker'' 
would normally take power generation equipment off-line in order to 
protect it from operating at a different frequency than the grid. The 
NOx data supports this scenario. The Fluid Catalytic Cracker, a 
critical part of the production process, showed increased 
NOX emissions through Wednesday, October 3, which is 
consistent with the flaring associated with a shutdown and startup 
procedure.
    Overall, the NOX data does not support a full plant 
closure as a result of the frequency problem at Southern California 
Edison. Other than the Fluid Catalytic Cracker, half of the NOx reports 
from Torrance stayed at normal operating ranges during this period. In 
fact, most of the metered units continued at an intermediate level of 
operations.
    By Wednesday, October 3, a Dow Jones Newswire article corroborated 
the NOX data:

          Update--ExxonMobil Says Operations Normalizing at Its 149,500 
        b/d Torrance, California Refinery by October 3 after Power 
        Outage October 1

          ExxonMobil Corp. said operations at its Torrance refinery 
        were getting back to normal following a plant-wide power outage 
        Monday morning. The power interruption, which was caused by an 
        outage at a Southern California Edison substation, resulted in 
        refinery unit shutdowns and slowdowns, which caused flaring. 
        ExxonMobil said flaring associated with the normalization 
        process could continue through October 9, ac-cording to a 
        filing with the Southern California Air Quality Management 
        District. The refinery anticipated only minimal impact to 
        production, and expected to meet all its contractual 
        commitments.\15\
---------------------------------------------------------------------------
    \15\ ``ExxonMobil: Torrance, California, Refinery Operations 
Normalizing after Power Outage.'' Dow Jones News-wires, October 3, 
2012.

    The frenzied trading on October 1, 2012 followed by additional 
wholesale price in-creases on October 2 and 3 seem anomalous. The 
trading activity on Monday appar-ently predated news about the scale of 
the problems of the Torrance refinery and the media significantly 
---------------------------------------------------------------------------
overstated the severity of the problem:

          REFINERY NEWS--ExxonMobil reports breakdown at Torrance, 
        California
          Houston (Platts)--1Oct2012/1222 pm EDT/1622 GMT Refinery: 
        Tor-rance, California Owner: ExxonMobil Overall capacity (b/d): 
        149,500 Units affected: N/A Units capacity (b/d): N/A Duration: 
        Emissions window 7:20 a.m. PDT to 11:59 p.m. PDT Monday Notes: 
        ExxonMo-bil's Torrance refinery suffered a breakdown Monday 
        leading to poten-tial emissions/flaring, according to an 
        unplanned flare event filing to state regulators.

          The company did not immediately respond to a request for 
        comment, but sources said the 149,500 b/d gasoline-centric 
        plant near Los Ange-les suffered a power failure.

          The filing did not specify the nature of the breakdown or 
        which unit or units may be involved. The filing said related 
        emissions exceeding al-lowed levels were, according to 
        estimates, more than 500,000 cubic feet of combusted vent gas 
        and more than 500 lbs of sulfur oxides.\16\
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    \16\ ``Refinery News: ExxonMobil reports breakdown at Torrance, 
California,'' Platts Commodity News, October 1, 2012.

    Logically, ExxonMobil might have immediately sought some additional 
supplies upon hearing of the shutdown of the cogeneration units. It 
would not have been logical for ExxonMobil to notify its competitors of 
its activities, nor for the competitors to immediately start buying in 
the market on receipt of a standard flare report at SCAQMD.
    A reasonable alternative explanation is that speculation in the 
California wholesale gas-oline market may have been the cause of the 
exaggerated media reports, and that the relatively minor outage at 
Torrance was viewed as an opportunity to secure windfall profits.




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