QEP MIDSTREAM PARTNERS, LP

1050 17^th Street, Suite 500

Denver, Colorado 80265

July 3, 2013

Via EDGAR and Fedex

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549-4628

Attn: Mara L. Ransom

Division of Corporation Finance

Re: QEP Midstream Partners, LP

Registration Statement on Form S-1

Filed May 9, 2013

File No. 333-188487

Ladies and Gentlemen:

Set forth below are the responses of QEP Midstream Partners, LP, a Delaware limited partnership (“we” or the “Partnership”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated June 7, 2013, with respect to the Partnership’s Form S-1 initially filed with the Commission on May 9, 2013, File No. 333-188487 (the “Registration Statement”).

Concurrently with the submission of this letter, we have filed through EDGAR Amendment No. 1 to the Registration Statement (“Amendment No. 1”). For your convenience, we have hand delivered five copies of this letter, as well as five copies of Amendment No. 1 marked to show all changes made since the initial filing of the Registration Statement.

For your convenience, each response is prefaced by the text of the Staff’s corresponding comment in bold text. All references to page numbers and captions correspond to the marked copy of Amendment No. 1 unless otherwise indicated.

QEP Midstream Partners, LP

July 3, 2013

Page 2

Registration Statement on Form S-1 Filed May 9, 2013

General

1.    We note a number of blank spaces throughout your registration statement for information that you are not entitled to omit under Rule 430A. Please revise throughout the prospectus to include all information that may not properly be excluded under Rule 430A. Please provide all information required with respect to the offering price, underwriting discounts and the number of shares. Please allow us sufficient time to review your complete disclosure prior to any distribution of preliminary prospectuses. We may have further comments once items that are currently blank are completed.

Response: We acknowledge the Staff’s comment and will undertake to provide in future amendments all omitted information in the Registration Statement that we are not entitled to omit under Rule 430A. We will allow sufficient time for the Staff to review our complete disclosure and for us to respond to any comments that may result from the Staff’s review prior to the distribution of the preliminary prospectus.

2.    All exhibits are subject to our review. Accordingly, please file or submit all of your exhibits with your next amendment, or as soon as possible. Please note that we may have comments on the legal opinion and other exhibits once they are filed. Understand that we will need adequate time to review these materials before accelerating effectiveness.

Response: We acknowledge the Staff’s comment and will undertake to file all omitted exhibits as soon as practicable. We have filed Exhibits 10.3, 10.4, 10.6, 10.7, 10.8, 10.9, 10.10, 10.11, 10.12, 21.1, 23.1 and 24.1 with Amendment No. 1. We will file all remaining exhibits to allow the Staff a sufficient amount of time to review them and for us to respond to any comments that may result from the Staff’s review prior to the distribution of the preliminary prospectus.

3.    Prior to the effectiveness of the registration statement, please arrange to have FINRA call us or provide us with a letter indicating that FINRA has completed its review, including its review regarding the underwriting compensation terms and arrangements of this offering, and has no objections.

Response: We acknowledge the Staff’s comment and will request that FINRA call the Staff or provide the Staff with a letter indicating that FINRA has completed its review and has no objections to the underwriting compensation terms and arrangements of this offering outlined in the Registration Statement.

4.    Please provide us with any gatefold information such as pictures, graphics or artwork that will be used in the prospectus.

Response: We have included in Amendment No. 1 copies of all artwork and any graphics that we propose to include in the prospectus prior to distribution of the preliminary prospectus. Please see the inside cover page of the prospectus for the new graphics.

QEP Midstream Partners, LP

July 3, 2013

Page 3

5.    We note you make assertions in your prospectus regarding your competitive position within your industry without providing supporting sources. Please disclose the basis for your assertions about your or your affiliates’ competitive position within your industry. The following are examples of only some of your unsupported assertions:

• “Our assets are located in, or are within close proximity to, the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the portion of the Williston Basin located in North Dakota, which are currently among the most economic and active drilling regions in the United States.” (Page 1)

• “Our customers are some of the largest natural gas producers in the Rocky Mountain region, including QEP, Anadarko Petroleum Corporation (Anadarko), EOG Resources, Inc. (EOG), Questar Corporation (Questar) and Ultra Resources, Inc. (Ultra).” (Page 1)

• “QEP is a leader among exploration and production companies in several of the most economic natural gas and crude oil basins in North America.” (Page 125)

Response: The Registration Statement has been revised as requested. Please see pages 1, 6, 7, 92, 113, 115 and 128.

6.    We note references throughout your prospectus to third-party sources for statistical, qualitative and comparative statements contained in your prospectus. For example, you refer to the United States Energy Information Administration on pages 105, 108 and 109, among other pages. Please provide copies of these source materials to us, appropriately marked to highlight the sections relied upon and cross-referenced to your prospectus. If you funded or were otherwise affiliated with any of the studies or reports you cite, please disclose this. Please also tell us whether these reports and articles are publicly available without cost or at a nominal expense to investors. If you do not have appropriate independent support for a statement, please revise the language to make clear that this is your belief based upon your experience in the industry, if true.

Response: We are supplementally providing to the Staff support for the third-party data contained in the prospectus. Please see Appendix A. We have not funded nor are we affiliated with any of the studies or reports cited in the Registration Statement. The information that is sourced to the United States Energy Information Administration (http://www.eia.gov/) is available to the public through its website.

7.    Please supplementally provide us with copies of all written communications, as defined in Rule 405 under the Securities Act, that you, or anyone authorized to do so on your behalf, present to potential investors in reliance on Section 5(d) of the Securities Act, whether or not they retain copies of the communications. Similarly, please supplementally provide us with any research reports about you that are published or distributed in reliance upon Section 2(a)(3) of the Securities Act of 1933 added by Section 105(a) of the Jumpstart Our Business Startups Act by any broker or dealer that is participating or will participate in your offering.

QEP Midstream Partners, LP

July 3, 2013

Page 4

Response: We have not provided, nor have we authorized anyone to provide on our behalf, written materials to potential investors that are qualified institutional buyers or institutional accredited investors in reliance on Section 5(d) of the Securities Act. The underwriters that are participating in the Partnership’s initial public offering have confirmed to us that they have not published or distributed any research reports about the Partnership in reliance upon Section 2(a)(3) of the Securities Act. We undertake to supplementally provide the Staff with any such materials to the extent such materials are utilized in the future.

Prospectus Cover Page

8.    Please revise your cover page to include the structuring fee in the table, rather than via footnote, or tell us why you believe this is not appropriate. Refer to Item 501(b)(3) of Regulation S-K.

Response: We acknowledge the Staff’s comment but respectfully submit that the structuring fee does not fall within the scope of Item 501(b)(3) of Regulation S-K. Wells Fargo Securities, LLC (“Wells Fargo”) will receive the structuring fee for advice that they provide to the Partnership prior to and leading up to the Partnership’s initial public offering (“IPO”). We believe the advisory services are analogous to accounting and legal services that have been provided to the Partnership in connection with the IPO. In response to this comment, however, we have revised the footnote to cross reference the disclosure under the caption “Use of Proceeds”, which has been revised to reflect that a portion of the net proceeds from the offering will be used to pay the structuring fee to Wells Fargo. Please see the cover page of the prospectus and pages 15 and 56.

Industry and Market Data, page v

9.    In the last sentence of the paragraph, you state that you “have not independently verified the information.” Under the federal securities laws, you are responsible for all information contained within your registration statement and should not include language that suggests otherwise. Please delete this statement or otherwise revise it to eliminate any implication that you are not responsible for information that you have chosen to include in your registration statement.

Response: The Registration Statement has been revised as requested. Please see page v.

Prospectus Summary, page 1

10.    Please balance the discussion of your business with a discussion of your principal competitive challenges and risks. Your cross reference to the Risk Factors section on page 9 is insufficient in this regard. Refer to Securities Act Release No. 33-6900.

QEP Midstream Partners, LP

July 3, 2013

Page 5

Response: The Registration Statement has been revised as requested. Please see pages 9 and 10.

QEP Midstream Partners, LP, page 1

Overview, page 1

11.    We note your statement in the third paragraph on page 2 that you “believe QEP will offer [you] the opportunity to purchase additional midstream assets from it . . . .” Please disclose the anticipated timeframe in which you expect QEP to offer you the opportunity to acquire additional assets of QEP, or state explicitly that you currently do not know when you will be provided with any such opportunity. Please make similar revisions throughout your prospectus, as applicable.

Response: The Registration Statement has been revised as requested. Please see pages 2, 5, 6, 95, 113, 114 and 115.

Our Relationship with QEP Resources, Inc., page 6

12.    We note your disclosure here and on page 19 that QEP will be retaining certain midstream assets and will not be contributing them to you. Please explain why these assets will not be contributed to you by QEP and how this may affect your business. If these assets are ones that QEP could sell to you in the future, please state as much.

Response: The Registration Statement has been revised as requested. Please see pages 8 and 129.

13.    Please disclose in this section or in another subheading in the prospectus summary, the amount(s) that QEP will receive in conjunction with this offering, including all cash distributions to QEP which will be funded from the proceeds of this offering. Please also include any payments, compensation, or the value of any equity that QEP, or the directors or executive officers of QEP received or will receive in connection with the offering.

Response: The amount of equity in the Partnership as well as the cash distribution that QEP will receive in connection with the IPO will be disclosed under the headings “Formation Transactions and Partnership Structure” and “The Offering” on pages 11 and 15, respectively, of the Prospectus Summary. We acknowledge the Staff’s comment seeking disclosure with respect to payments, compensation, or the value of any equity that QEP, or the directors or executive officers of QEP received or will receive in connection with the IPO. Except as otherwise disclosed in the Registration Statement under the captions “Use of Proceeds,” “Management–Executive Compensation,” “Management–Director Compensation” and “Security Ownership and Certain Beneficial Owners and Management,” it is the current expectation that QEP and its directors and officers will not receive any additional payments, compensation or equity. If it is subsequently determined that QEP or its directors or officers, including those individuals that are directors and officers of both QEP and the Partnership’s general partner, will receive additional payments, compensation or equity, including equity granted under the Partnership’s long-term incentive plan, we will undertake to provide such information in future amendments.

QEP Midstream Partners, LP

July 3, 2013

Page 6

Summary Historical and Pro Forma Financial and Operating Data, page 19

14.    We note your disclosure in the third paragraph on page 19 that the pro forma combined financial data assumes the transactions reflected in such information occurred as of January 1, 2012. Please revise to state, if true, that the pro forma balance sheet data has been presented as if the transactions had occurred at the balance sheet date, and the pro forma statement of operations data has been presented as if the transactions had occurred at January 1, 2012, similar to your disclosure on page F-2.

Response: The Registration Statement has been revised as requested. Please see pages 20 and 87.

15.    We note your presentation of Adjusted EBITDA on page 21. Considering that the disclosures required by Item 10(e) of Regulation S-K are presented more than 60 pages after this presentation of Adjusted EBITDA, please revise your cross-reference to the reconciliation and discussion of how you use this measure to also include page numbers. We believe this will make it easier for your investors to locate this important information concerning your non-GAAP measure.

Response: The Registration Statement has been revised as requested. Please see page 21.

Capitalization, page 56

16.    We note the description of your pro forma capitalization and your pro forma as adjusted capitalization in the second and third bullet points under this heading. For the ease of your investors, please describe in more detail the types of adjustments and transactions that were applied to your “Historical” balances to result in your “Pro Forma” and “Pro Forma as Adjusted” balances.

Response: The Registration Statement has been revised as requested. Please see page 57.

Risk Factors, page 22

Risks Related to Our Business, page 22

Our Ability to Operate Our Business Effectively Could Be Impaired If We Fail to Attract and Retain Key Management Personnel, page 40

17.    Please identify the extent to which you rely on employees of QEP and its affiliates. For example, describe whether you depend on QEP and its affiliates for every level of management. Based on your disclosure on page 140, we understand that you will have no employees. Similarly, please also identify whether you or the general partner have key person life insurance policies for executive officers. If this is the case, then identify whether any proceeds received from these life insurance policies would be sufficient to cover a loss of these persons.

QEP Midstream Partners, LP

July 3, 2013

Page 7

Response: The Registration Statement has been revised as requested. Please see pages 40 and 41.

Risks Inherent in an Investment in Us, page 41

Cost Reimbursements, Which Will Be Determined in Our General Partner’s Sole Discretion . . . , page 45

18.    Please briefly describe and quantify the general partner’s expenses that must be paid. We note your reference to such reimbursements on page 151, however, it does not appear that these expenses are discussed here. Refer to Securities Act Release No. 33-6900.

Response: The Registration Statement has been revised as requested. Please see pages 13, 46, 60 and 155.

There is No Existing Market for Our Common Units…, page 48

19.    Please expand the risk factor summary on your prospectus cover page to include a summary of this risk factor. Refer to Section II.A.3.a of Securities Act Release 33-6900 (June 17, 1991).

Response: The Registration Statement has been revised as requested. Please see the prospectus cover page.

Use of Proceeds, page 55

20.    You state here that you had approximately $146.8 million of debt outstanding comprised of intercompany loans from QEP. You indicate elsewhere that you will have no debt outstanding after this offering. If the amount of debt you are referring to here relates to debt held by QEP Operating, please clarify to state as much or explain.

Response: The Registration Statement has been revised as requested. Please see page 56.

Cash Distribution Policy and Restrictions on Distributions, page 58

21.    When you file the next amendment to your registration statement, please provide unaudited pro forma cash available for distribution for your most recent 12 months in addition to the information provided for your most recent year ended December 31, 2012.

Response: The Registration Statement has been revised as requested. Please see pages 63 through 65.

22.    We note that there is currently a six month gap between your presentation of unaudited pro forma cash available for distribution for the year ended December 31, 2012

QEP Midstream Partners, LP

July 3, 2013

Page 8

and your estimated cash available for distribution for the 12 months ending June 30, 2014. If you continue to have a gap between the periods of your backward looking and forward looking calculations of cash available for distribution, please disclose whether anything in the gap period is expected to differ materially from the assumptions disclosed in your forecast. Please also note that the projected period of estimated cash available for distribution should be the closest 12 month period succeeding the estimated close date of your offering.

Response: We have provided updated financial statements in Amendment No. 1 that reflect our financial condition and results of operations for the three months ended March 31, 2013. Accordingly, we have revised our presentation of unaudited pro forma cash available for distribution to include the twelve-month period ended March 31, 2013, reducing the gap between our backcast and forecast calculations of cash available for distribution to three months. Given that the twelve month period included in the backcast is derived from the Partnership’s unaudited pro forma financial information, we are unable to update such information to be as of a more recent date. If the Registration Statement is declared effective by early-August, we believe that the twelve month period ending June 30, 2014 is the most meaningful forecast period for investors because it will cover the four-quarter period closest to the expected closing date of our offering. If the Registration Statement is not declared effective by early-August, we intend to update our forecast to cover the twelve month period ending September 30, 2014.

Our Minimum Quarterly Distribution, page 60

23.    Please revise your table to show the Minimum Quarterly Distributions assuming both no, and full exercise of the underwriter’s option to purchase additional common units.

Response: The Registration Statement has been revised as requested. Please see page 61.

Assumptions and Considerations, page 67

General Considerations and Sensitivity Analysis, page 67

24.    Please reconcile the statement in the second bullet point that you expect production from QEP in the Pinedale Field to be your primary growth driver going forward with your disclosures in the third bullet point and throughout your discussion of revenue on pages 68 and 69 that during the 12 months ended June 30, 2014 you will have decreased gathering and transportation volumes from the Pinedale Field.

Response: The Registration Statement has been revised as requested. Please see page 68.

25.    We note your disclosure at the top of page 68 that you included the disputed fee amount with QEP Field Services in your pro forma cash available for distribution for the year ended December 31, 2012 but you excluded it from your forecast. Please quantify for your investors an estimate of the disputed fee amount for the 12 months ended June 30, 2014 or explain to us in detail why you cannot estimate this amount. Since the dispute relates to the gathering rate being charged, it appears that the disputed amount could vary from period to period depending on the volumes gathered.

QEP Midstream Partners, LP

July 3, 2013

Page 9

Response: The Registration Statement has been revised as requested. Please see page 69.

Condensate sales, page 69

26.    Please disclose the increased condensate sales volumes and the forecasted sales price per barrel of condensate used in estimating revenue from such sales for the twelve months ending June 30, 2014.

Response: The Registration Statement has been revised as requested. Please see page 70.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 91

General Trends and Outlook, page 93

Acquisition Opportunities, page 94

27.    We note your potential growth through acquisitions from QEP and from third parties. Please discuss in this section any of your current plans in this regard, with a view to providing investors with a description of your planned operations.

Response: The Registration Statement has been revised as requested. Please see pages 2, 5, 6, 95, 113, 114 and 115.

Liquidity and Capital Resources, page 98

Capital Requirements, page 99

28.    To the extent known, please discuss in this section your anticipated material commitments for capital expenditures. See Item 303(a)(2) of Regulation S-K.

Response: The Registration Statement has been revised as requested. Please see pages 102 and 103.

29.    Please revise to include a summary of the key terms of the credit facility you intend to enter in connection with the closing of your offering. Specify succinctly in a bullet point list the covenants and conditions of the agreement that may affect your distribution of available cash to common unit holders even without the imminence or occurrence of a default.

Response: We acknowledge the Staff’s comment and respectfully advise the Staff that we are currently negotiating the terms of our proposed new credit facility with the potential lenders and that we expect to finalize those terms prior to the commencement of this offering. We hereby undertake to update our disclosure to reflect the material terms of our new credit facility, including the conditions that we must satisfy prior to making distributions, once those terms have been agreed to by the respective parties.

QEP Midstream Partners, LP

July 3, 2013

Page 10

Industry Overview, page 104

Contractual Arrangements, page 107

30.    With a view to disclosure, please enhance this discussion to explain “life-of reserves” contracts, which you refer to elsewhere in your prospectus. Please also clarify the nature of the agreements you enter into with respect to your oil gathering and transmission operations, as this discussion appears to be restricted to your midstream natural gas operations.

Response: The Registration Statement has been revised as requested. Please see pages 110 and 111.

Business, page 110

Competition, page 127

31.    Please identify your competitive position relative to the competitors you have listed. See Item 101(c)(x) of Regulation S-K.

Response: Due to the significant range of competitors in the regions in which we operate, several of which are independent private companies, and because competitors continuously enter and exit our areas of operation, we have identified who we think of as our principal competitors. The entities that are identified in the prospectus as our principal competitors are large, midstream oil and natural gas entities, with assets in many geographic regions, only some of which are located in the areas in which we operate. Because our principal competitors do not disclose the results of operations, financial condition or operating data specifically for their assets in the areas in which we operate, we are not able to know or assess our competitive position relative to those entities.

Certain Relationships and Related Party Transactions, page 151

Distributions and Payments to Our General Partner and Its Affiliates, page 151

Formation Stage, page 151

32.    Please confirm to us that you will disclose the amount of common units and subordinated units to be beneficially owned by your general partner and its affiliates after the completion of the offering contemplated by the registration statement and the percentage of outstanding common units and subordinated units, respectively, represented by such amount.

QEP Midstream Partners, LP

July 3, 2013

Page 11

Response: We acknowledge the Staff’s comment and confirm that we will disclose the requested information in a subsequent amendment to the Registration Statement.

Operational Stage, page 151

33.    Please disclose, and quantify to the extent possible, in this section and elsewhere as applicable, the direct and indirect expenses to which your general partner will be entitled to reimbursement prior to determining the amount of cash you have available for distributions.

Response: The Registration Statement has been revised as requested. Please see pages 13, 46, 60 and 155.

Lock-Up Agreements, page 203

34.    You indicate that Wells Fargo Securities, LLC “may, in its sole discretion and at any time or from time to time, without notice, release all or any portion of the common units or other securities subject to the lock-up agreements.” Please disclose whether there are any agreements, understandings or intentions, tacit or explicit, to release any of the securities from the lock-ups prior to the expiration of the corresponding period. If so or if it constitutes a material risk, provide appropriate Risk Factors disclosure regarding the discretionary power to release all such “locked-up” securities.

Response: The Registration Statement has been revised as requested. Please see pages 49 and 207.

Where You Can Find Additional Information, page 207

35.    We note your statement on page 207 that “This prospectus does not contain all of the information found in the registration statement.” While you can provide summaries and not complete descriptions, all material information must be presented. Please revise the prospectus to include all material information and revise the statement we quote above.

Response: We acknowledge the Staff’s comment and have revised the Registration Statement to reflect that we have provided all material information in the prospectus and have omitted only the information permitted by the rules and regulations of the SEC. Please see page 210.

Index to Financial Statements, page F-1

General

36.    Please update your combined financial statements to include unaudited interim financial statements as required by Rule 8-08 of Regulation S-X. Please refer to Rule 8-03 of Regulation S-X for guidance on preparation of such interim financial statements. Please also update your unaudited pro forma combined financial information as required by Rule 8-05 of Regulation S-X.

QEP Midstream Partners, LP

July 3, 2013

Page 12

Response: The Registration Statement has been revised as requested. Please see pages F-2 through F-18.

Unaudited Pro Forma Combined Financial Statements, page F-2

Unaudited Pro Forma Combined Statement of Income, page F-4

37.    We note that your Incentive Distribution Rights (IDRs) appear to be separately transferable. Please provide a footnote to your pro forma combined financial statements which explains how earnings or losses for a reporting period will be allocated to the general partner, the limited partners and to the holder(s) of the IDRs to compute earnings per common unit. Please refer to ASC 260-10-45-72 and 45-73.

Response: The Registration Statement has been revised as requested. Please see page F-8.

Notes to Unaudited Pro Forma Combined Financial Statements, page F-6

Note 3. Pro Forma Adjustments, page F-6

38.    We note your disclosure in Note 3 (e) that if the underwriters were to exercise their option to purchase additional common units in full, gross proceeds to the Partnership would equal $400 million. We note your disclosures on pages 14, 55 and 57 that proceeds from the sale of such additional common units will not be retained by the Partnership. If true, please revise to also disclose that the net proceeds from any exercise by the underwriters of this option will be used by you to redeem from QEP a number of common units equal to the number of common units issued upon exercise of such option and will not be retained by the Partnership. If otherwise, please explain and revise your disclosures as appropriate.

Response: The Registration Statement has been revised as requested. Please see page F-8.

Part II, page II-1

Item 15. Recent Sales of Unregistered Securities, page II-1

39.    Please expand your disclosure on page II-1 to briefly state the facts relied upon in making the Section 4(2) exemption available for the transaction discussed.

Response: The Registration Statement has been revised as requested. Please see Part II, page II-1.

Item 16. Exhibits, page II-2

QEP Midstream Partners, LP

July 3, 2013

Page 13

40.    We note that several of the exhibits that you plan to file by amendment are “form of” agreements. Please confirm that the “form of” agreements that you plan to file will be consistent with Instruction 1 to Item 601 of Regulation S-K, and that any “form of” agreement that deviates from the final agreement in any way will be re-filed accordingly.

Response: We acknowledge the Staff’s comment and respectfully advise the Staff that the “form of” agreements that we plan to file will be consistent with Instruction 1 to Item 601 of Regulation S-K, and that any “form of” agreement that deviates from the final agreement in any way will be re-filed accordingly.

Item 17. Undertakings

41.    Please provide the undertakings set forth at Item 512(a)(5)(ii) and Item 512(a)(6) of Regulation S-K.

Response: The Registration Statement has been revised as requested. Please see Part II, page II-3 of Amendment No. 1.

QEP Midstream Partners, LP

July 3, 2013

Page 14

We hereby acknowledge the Staff’s closing comments to the letter and hereby undertake to comply with the Staff’s requests. Please direct any questions or comments regarding the foregoing to the undersigned or to our counsel at Latham & Watkins LLP, Sean T. Wheeler at (713) 546-7418.

Very Truly Yours,
QEP MIDSTREAM PARTNERS, LP
By:	QEP Midstream Partners GP, LLC, its general partner
By:	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer

Cc: Jacqueline Kaufman, Securities and Exchange Commission

Sondra Snyder, Securities and Exchange Commission

Jennifer Thompson, Securities and Exchange Commission

Sean T. Wheeler, Latham & Watkins LLP

Jeffery K. Malonson, Vinson & Elkins LLP

Douglas E. McWilliams, Vinson & Elkins LLP

Appendix A

[Please see attached]

Refined petroleum products, such as jet fuel, gasoline and distillate fuel oil, are all sources of energy derived from crude oil. According to 2011 data compiled by the EIA, petroleum currently accounts for about 36% of the nation’s total annual energy consumption. The diagram below depicts the segments of the crude oil value chain:

Natural Gas Midstream Services

The range of services utilized by midstream natural gas service providers are generally divided into the following seven categories:

Gathering.At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads, pad sites or other receipt points in the production area. These gathering systems transport natural gas from the wellhead to downstream pipelines or a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures.

Compression.Gathering systems are operated at design pressures that enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be brought to market. Since wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintain throughput across the gathering system.

Treating and Dehydration.Another process in the midstream value chain is treating and dehydration, a step that involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. These impurities must be removed for the natural gas to meet the specifications for transportation on long-haul intrastate and interstate pipelines. Moreover, end users will not purchase natural gas with a high level of these impurities. To meet downstream pipeline and end user natural gas quality standards, the natural gas is dehydrated to remove the saturated water and is chemically treated to separate the impurities from the natural gas stream.

Processing.The principal components of natural gas are methane and ethane, but most natural gas also contains varying amounts of other NGLs, which are heavier hydrocarbons that are found in some natural gas streams. Even after treating and dehydration, most natural gas is not suitable for long-haul intrastate and interstate pipeline transportation or commercial use because it contains NGLs, as well as natural gas condensate. This natural gas, referred to as liquids-rich natural gas, must be processed to

108

108a

Interruptible Service. Interruptible service is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of natural gas or crude oil actually gathered, transported, or, in the case of natural gas, processed. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the processing facility.

Dedication Provisions

Any of midstream contracts referenced above may provision that in the industry are, often referred to as “life-of-reserves” or “life-of-lease” dedications. The provisions effectively dedicate any and all production from specified leases or existing and future wells on dedicated lands for as long there is commercial production from such identified wells or leases. These provisions contain dedications that typically remain in effect even if ownership of the subject acreage or well changes in the future.

U.S. Natural Gas Fundamentals

Natural Gas Demand

Natural gas is a significant component of energy consumption in the United States. According to the EIA, natural gas consumption accounted for approximately 27% of all energy used in the United States in 2012, representing 25.5 Tcf of natural gas. The EIA estimates that over the next 30 years, total domestic energy consumption will increase by over 10%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and natural gas vehicles. The following charts show the allocation of natural gas usage by end user as well as the relative position of natural gas as a power generation fuel source as of 2012.

Source: EIA, Annual Energy Outlook 2013 (April 2013).

According to the EIA, during the period from 2001 through 2012, natural gas consumption increased by 14.5% overall from an average of approximately 60.9 Bcf/d in 2001 to an average of approximately 69.7 Bcf/d in 2012. Although the change in consumption levels during this period was variable on a year-to-year basis, growth was highest in the seasonal and weather-sensitive electric power generation sector, where consumption grew by approximately 71.0%. The growth in this sector was partially offset by an approximate 12.5% decline in natural gas consumption in the residential sector.

Forecasts published by the EIA and other industry sources anticipate that long-term domestic demand for natural gas will continue to grow, and that the historical trend of growth in natural gas demand from

111

110A 110B 110C 110D 110E 110F 110G 110H 110I 110J

seasonal and weather-sensitive consumption sectors will continue. These forecasts are supported by various factors, including (i) expectations of continued growth in the U.S. gross domestic product, which has a significant influence on long-term growth in natural gas demand; (ii) an increased likelihood that regulatory and legislative initiatives regarding domestic carbon policy will drive greater demand for cleaner burning fuels like natural gas; (iii) increased acceptance of the view that natural gas is a clean and abundant domestic fuel source that can lead to greater energy independence for the United States by reducing its dependence on imported petroleum; (iv) the emergence of low-cost natural gas shale developments, which suggest ample supplies and which are expected to keep natural gas prices low relative to crude oil prices, making the commodity attractive as a feedstock; and (v) continued growth in electricity generation from intermittent renewable energy sources, primarily wind and solar energy, for which natural-gas fired generation is a logical back-up power supply source. According to the EIA, natural gas consumption is expected to rise from 69.9 Bcf/d in 2012 to 80.8 Bcf/d in 2040.

Natural Gas Supply

Domestic natural gas consumption is currently satisfied primarily by production from conventional onshore and offshore production in the lower 48 states, as supplemented by production from historically declining pipeline imports from Canada, imports of LNG from foreign sources, and some Alaska production. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds) increasing from 9.5% of total U.S. natural gas supply in 2000 to 36.1% in 2011. According to EIA data, during the five-year period from January 2007 through December 2012, marketed domestic production of natural gas increased by an average of approximately 4.6% per annum, largely due to continued development of shale resources. The emergence of shale plays has resulted primarily from advances in horizontal drilling and hydraulic fracturing technologies, which have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

In 2012, the EIA estimated that the United States held 542 Tcf of technically recoverable shale gas resource. As the depletion of onshore conventional and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the void and continue to gain market share from higher-cost sources of natural gas. As shown in the graph below, natural gas production from the major shale formations is forecast to provide the majority of the growth in domestically produced natural gas supply, increasing to approximately 50% in 2040 as compared with 34% in 2011.

Natural Gas Production (Tcf) by Source, 1990-2040

Source: EIA, Annual Energy Outlook 2013 (April 2013).

110H 112A 112B 112C 112D 112E 112F

113

DOE/EIA-0384(2011) | September 2012

Annual Energy Review 2011

Eia

INDEPENDENT STATISTICS & ANALYSIS

U.S. ENERGY INFORMATION ADMINISTRATION

WWW.EIA.GOV/AER

Figure 2.0 Primary Energy Consumption by Source and Sector, 2011

(Quadrillion Btu)

108A

SOURCE

Petroleum1

35.3

(36%)

Natural Gas2

24.8

(26%)

Coal3

19.7

(20%)

Renewable energy4

9.1(9%)

Nuclear electric power

8.3 (8%)

Total = 97.3

Percent of sources

Percent of sectors

Sector

Transportation

27.0

(28%)

Industrial5

20.3

(21%)

Residential &

Commercial6

10.7 (11%)

Electric Power7

39.3

(40%)

71

23

5

1

3

32

33

31

8

<1

92

13

25

8

54

100

93

3

4

40

41

8

11

17

75

1

7

1

20

46

13

21

–

1 Does not include biofuels that have been blended with petroleum—biofuels are included in

“Renewable Energy.”

2 Excludes supplemental gaseous fuels.

3 Includes less than 0.1 quadrillion Btu of coal coke net imports.

4 Conventional hydroelectric power, geothermal, solar/photovoltaic, wind, and biomass.

5 Includes industrial combined-heat-and-power (CHP) and industrial electricity-only plants.

6 Includes commercial combined-heat-and-power (CHP) and commercial electricity-only plants.

7 Electricity-only and combined-heat-and-power (CHP) plants whose primary business is to

sell electricity, or electricity and heat, to the public. Includes 0.1 quadrillion Btu of electricity net

imports not shown under “Source.”

Notes: Primary energy in the form that it is first accounted for in a statistical energy balance,

before any transformation to secondary or tertiary forms of energy (for example, coal is used to

generate electricity). • Sum of components may not equal total due to independent rounding.

Sources: U.S. Energy Information Administration, Annual Energy Review 2011, Tables 1.3,

2.1b-2.1f , 10.3, and 10.4.

U.S. Energy Information Administration / Annual Energy Review 2011

37

DOE/EIA-0035(2013/04)

April 2013

Monthly Energy Review

Eia

INDEPENDENT STATISTICS & ANALYSIS

U.S. ENERGY INFORMATION ADMINISTRATION

WWW.EIA.GOV/MER

Table 1.3 Primary Energy Consumption by Source

(Quadrillion Btu)

Fossil Fuels Renewable Energya

Nuclear Hydro-

Natural Petro- Electric electric Geo- Solar/ Bio-

Coal Gasb leumc Totald Power Powere thermal PV Wind mass Total Totalf

1973 Total 12.971 22.512 34.837 70.314 0.910 2.861 0.020 NA NA 1.529 4.411 75.684

1975 Total 12.663 19.948 32.732 65.357 1.900 3.155 .034 NA NA 1.499 4.687 71.965

1980 Total 15.423 20.235 34.205 69.828 2.739 2.900 .053 NA NA 2.475 5.428 78.067

1985 Total 17.478 17.703 30.925 66.093 4.076 2.970 .097(s)(s) 3.016 6.084 76.392

1990 Total 19.173 19.603 33.552 72.332 6.104 3.046 .171 .059 .029 2.735 6.041 84.485

1995 Total 20.089 22.671 34.438 77.259 7.075 3.205 .152 .069 .033 3.101 6.560 91.029

1996 Total 21.002 23.085 35.675 79.785 7.087 3.590 .163 .070 .033 3.157 7.014 94.022

1997 Total 21.445 23.223 36.159 80.873 6.597 3.640 .167 .070 .034 3.105 7.016 94.602

1998 Total 21.656 22.830 36.816 81.369 7.068 3.297 .168 .069 .031 2.927 6.493 95.018

1999 Total 21.623 22.909 37.838 82.427 7.610 3.268 .171 .068 .046 2.963 6.516 96.652

2000 Total 22.580 23.824 38.262 84.731 7.862 2.811 .164 .066 .057 3.008 6.106 98.814

2001 Total 21.914 22.773 38.186 82.902 8.029 2.242 .164 .064 .070 2.622 5.163 96.168

2002 Total 21.904 23.510 38.224 83.699 8.145 2.689 .171 .063 .105 2.701 5.729 97.645

2003 Total 22.321 22.831 38.811 84.014 7.959 2.793 .173 .062 .113 2.807 5.948 97.943

2004 Total 22.466 22.923 40.292 85.819 8.222 2.688 .178 .063 .142 3.010 6.081 100.160

2005 Total 22.797 22.565 40.388 85.794 8.161 2.703 .181 .063 .178 3.117 6.242 100.282

2006 Total 22.447 22.239 39.955 84.702 8.215 2.869 .181 .068 .264 3.267 6.649 99.629

2007 Total 22.749 23.663 39.774 86.211 8.455 2.446 .186 .076 .341 3.474 6.523 101.296

2008 Total 22.385 23.843 37.280 83.549 8.427 2.511 .192 .089 .546 3.849 7.186 99.275

2009 Total 19.692 23.416 35.403 78.488 8.356 2.669 .200 .098 .721 3.912 7.600 94.559

2010 Total 20.791 24.575 36.010 81.369 8.434 2.539 .208 .126 .923 4.294 8.090 97.982

2011 January 1.888 2.940 3.006 7.835 .761 .248 .018 .012 .083 .369 .731 9.337

February 1.560 2.497 2.696 6.754 .678 .234 .017 .012 .102 .339 .703 8.143

March 1.544 2.276 3.070 6.892 .687 .303 .018 .013 .102 .369 .805 8.393

April 1.421 1.863 2.879 6.164 .571 .303 .017 .013 .121 .349 .804 7.546

May 1.551 1.695 2.938 6.185 .597 .317 .018 .014 .114 .363 .826 7.620

June 1.758 1.684 2.973 6.416 .683 .312 .017 .014 .107 .374 .824 7.934

July 1.953 1.913 2.995 6.861 .757 .304 .018 .014 .073 .374 .782 8.417

August 1.917 1.914 3.101 6.935 .746 .250 .018 .014 .073 .386 .741 8.439

September 1.614 1.677 2.923 6.214 .700 .208 .017 .013 .067 .365 .670 7.594

October 1.475 1.773 2.998 6.246 .663 .192 .018 .013 .102 .373 .699 7.617

November 1.425 2.053 2.929 6.406 .675 .201 .018 .013 .121 .375 .727 7.816

December 1.556 2.574 2.957 7.089 .752 .231 .018 .013 .104 .395 .760 8.612

Total 19.663 24.860 35.465 79.999 8.269 3.103 .212 .158 1.168 4.432 9.072 97.467

2012 January R 1.491 2.804 2.889 R 7.187 .757 .227 .019 .015 .134 .367 .763 R 8.718

February R 1.335 2.550 2.777 R 6.662 .668 .198 .018 .015 .108 .351 .690 R 8.030

March R 1.232 2.165 2.883 R 6.282 .646 .250 .019 .017 .135 .365 .786 R 7.725

April R 1.113 1.994 2.815 R 5.928 .585 .254 .018 .017 .124 .353 .767 R 7.292

May R 1.331 1.908 2.964 R 6.204 .650 .277 .019 .019 .122 .378 .816 R 7.684

June R 1.498 1.903 2.911 R 6.312 .682 .259 .019 .019 .116 .366 .779 R 7.786

July R 1.789 R 2.111 2.957 R 6.858 .723 .260 .019 .019 .085 .369 .753 R 8.353

August R 1.718 2.040 3.051 R 6.808 .728 .225 .019 .019 .081 .375 .719 R 8.274

September R 1.453 1.834 2.788 R 6.073 .675 .171 .019 .018 .084 .352 .644 R 7.406

October R 1.405 1.928 2.955 R 6.285 .625 .157 .019 .019 .122 .364 .681 R 7.604

November R 1.471 R 2.195 2.849 R 6.512 .593 .183 .019 .017 .112 .356 .687 R 7.806

December 1.536 2.521 2.849 R 6.906 .718 .226 .020 .017 .138 .367 .767 8.402

Total R 17.372 25.954 34.688 R 78.017 8.050 2.687 .227 .212 1.361 4.364 8.851 R 95.080

2013 January 1.562 2.920 2.936 7.417 .747 .244 .019 .017 .141 .364 .786 8.964

a Most data are estimates. See Tables 10.1–10.2c for notes on series

components and estimation; and see Note, “Renewable Energy Production and

Consumption,” at end of Section 10.

b Natural gas only; excludes supplemental gaseous fuels. See Note 3,

“Supplemental Gaseous Fuels,” at end of Section 4.

c Petroleum products supplied, including natural gas plant liquids and crude oil

burned as fuel. Does not include biofuels that have been blended with

petroleum—biofuels are included in “Biomass.”

d Includes coal coke net imports. See Tables 1.4a and 1.4b.

e Conventional hydroelectric power.

f Includes coal coke net imports and electricity net imports, which are not

separately displayed. See Tables 1.4a and 1.4b.

R=Revised. NA=Not available. (s)=Less than 0.5 trillion Btu.

Notes: •See “Primary Energy Consumption” in Glossary.

•Totals may not equal sum of components due to independent rounding.

•Geographic coverage is the 50 States and the District of Columbia.

Web Page: See http://www.eia.gov/totalenergy/data/monthly/#summary for all

available data beginning in 1973.

Sources: •Coal: Tables 6.1 and A5. •Natural Gas: Tables 4.1 and A4.

•Petroleum: Table 3.6. •Nuclear Electric Power: Tables 7.2a and A6

(“Nuclear Plants” heat rate). •Renewable Energy: Table 10.1. •Net Imports of

Coal Coke and Electricity: Tables 1.4a and 1.4b.

U.S. Energy Information Administration / Monthly Energy Review April 2013 7

110A

25.954

95.080 = .27=>27%

Table 4.1 Natural Gas Overview

(Billion Cubic Feet)

Supple- Trade Net

Gross Marketed mental Storage

With- Production Extraction Dry Gas Gaseous Net With- Balancing Consump-

drawalsa(Wet)b Lossc Productiond Fuelse Imports Exports Imports drawalsf Itemg tionh

1973 Total 24,067 i 22,648 917 i 21,731 NA 1,033 77 956 -442 -196 22,049

1975 Total 21,104 i 20,109 872 i 19,236 NA 953 73 880 -344 -235 19,538

1980 Total 21,870 20,180 777 19,403 155 985 49 936 23 -640 19,877

1985 Total 19,607 17,270 816 16,454 126 950 55 894 235 -428 17,281

1990 Total 21,523 18,594 784 17,810 123 1,532 86 1,447 -513 307 j 19,174

1995 Total 23,744 19,506 908 18,599 110 2,841 154 2,687 415 396 22,207

1996 Total 24,114 19,812 958 18,854 109 2,937 153 2,784 2 860 22,609

1997 Total 24,213 19,866 964 18,902 103 2,994 157 2,837 24 871 22,737

1998 Total 24,108 19,961 938 19,024 102 3,152 159 2,993 -530 657 22,246

1999 Total 23,823 19,805 973 18,832 98 3,586 163 3,422 172 -119 22,405

2000 Total 24,174 20,198 1,016 19,182 90 3,782 244 3,538 829 -306 23,333

2001 Total 24,501 20,570 954 19,616 86 3,977 373 3,604 -1,166 99 22,239

2002 Total 23,941 19,885 957 18,928 68 4,015 516 3,499 467 65 23,027

2003 Total 24,119 19,974 876 19,099 68 3,944 680 3,264 -197 44 22,277

2004 Total 23,970 19,517 927 18,591 60 4,259 854 3,404 -114 461 22,403

2005 Total 23,457 18,927 876 18,051 64 4,341 729 3,612 52 236 22,014

2006 Total 23,535 19,410 906 18,504 66 4,186 724 3,462 -436 103 21,699

2007 Total 24,664 20,196 930 19,266 63 4,608 822 3,785 192 -203 23,104

2008 Total 25,636 21,112 953 20,159 61 3,984 963 3,021 34 2 23,277

2009 Total 26,057 21,648 1,024 20,624 65 3,751 1,072 2,679 -355 -103 22,910

2010 Total 26,816 22,382 1,066 21,316 65 3,741 1,137 2,604 -13 115 24,087

2011 January 2,299 1,953 92 1,861 5 372 136 236 811 -31 2,882

February 2,104 1,729 82 1,647 4 311 125 186 594 16 2,448

March 2,411 2,002 95 1,908 5 315 145 171 151 -3 2,232

April 2,350 1,961 93 1,868 5 278 127 151 -216 20 1,828

May 2,411 2,031 96 1,935 5 271 132 139 -405 -10 1,663

June 2,313 1,954 92 1,862 5 267 120 147 -346 -15 1,653

July 2,340 2,033 96 1,937 5 293 113 180 -248 3 1,877

August 2,370 2,057 97 1,960 5 280 111 169 -249 -7 1,878

September 2,358 1,987 94 1,893 5 252 127 125 -404 27 1,646

October 2,502 2,119 100 2,019 5 282 110 173 -391 -65 1,741

November 2,476 2,076 98 1,978 5 249 128 121 -41 -50 2,014

December 2,544 2,135 101 2,034 5 298 134 163 390 -69 2,524

Total 28,479 24,036 1,134 22,902 60 3,469 1,507 1,962 -354 -185 24,385

2012 January 2,573 E 2,149 105 E 2,044 6 281 130 151 545 5 2,750

February 2,378 E 1,989 99 E 1,890 5 270 130 140 459 6 2,500

March 2,537 E 2,123 105 E 2,017 6 265 141 124 -39 16 2,124

April 2,445 E 2,065 102 E 1,963 4 243 123 120 -137 5 1,956

May 2,530 E 2,139 105 E 2,034 4 259 133 126 -283 -11 1,871

June 2,420 E 2,061 100 E 1,962 5 260 125 134 -230 -4 1,867

July 2,458 E 2,139 103 E 2,036 5 281 118 162 -134 2 2,071

August 2,374 E 2,130 104 E 2,026 5 281 139 142 -168 -4 2,001

September 2,428 E 2,087 105 E 1,981 5 258 137 121 -291 -16 1,800

October 2,569 RE 2,167 111 RE 2,056 5 253 140 113 -241 R -42 1,892

November 2,496 RE 2,100 109 RE 1,991 5 233 142 R 91 125 R -60 2,154

December R 2,562 E 2,149 107 E 2,041 6 251 159 R 92 385 R -52 2,472

Total R 29,771 RE 25,298 1,257 RE 24,042 62 3,135 1,619 R 1,516 -10 R -153 25,457

2013 January 2,542 E 2,127 105 E 2,022 6 276 155 121 722 -7 2,864

a Gases withdrawn from natural gas, crude oil, coalbed, and shale gas wells. Includes natural gas, natural gas plant liquids, and nonhydrocarbon gases; but excludes lease condensate. b Gross withdrawals minus repressuring, nonhydrocarbon gases removed, and vented and flared. See Note 1, “Natural Gas Production,” at end of section. c See Note 2, “Natural Gas Extraction Loss,” at end of section. d Marketed production (wet) minus extraction loss. e See Note 3, “Supplemental Gaseous Fuels,” at end of section. f Net withdrawals from underground storage. For 1980-2011, also includes net withdrawals of liquefied natural gas in above-ground tanks. See Note 4, “Natural Gas Storage,” at end of section. g See Note 5, “Natural Gas Balancing Item,” at end of section. Since 1980, excludes transit shipments that cross the U.S.-Canada border (i.e., natural gas delivered to its destination via the other country). h See Note 6, “Natural Gas Consumption,” at end of section. i May include unknown quantities of nonhydrocarbon gases.

j For 1989-1992, a small amount of consumption at independent power producers may be counted in both “Other Industrial” and “Electric Power Sector” on Table 4.3. See Note 7, “Natural Gas Consumption, 1989-1992,” at end of section.

R=Revised. E=Estimate. NA=Not available.

••Notes: •••See Note 8, “Natural Gas Adjustments, 1993-2000,” at end of section.

•••Totals may not equal sum of components due to independent rounding. Geographic coverage is the 50 States and the District of Columbia.

Web Page: See http://www.eia.gov/totalenergy/data/monthly/#naturalgas for all available data beginning in 1973.

••Sources: • Imports and Exports: Table 4.2. •••Consumption: Table 4.3.

Balancing Item: Calculated as consumption minus dry gas production, supplemental gaseous fuels, net imports, and net storage withdrawals. •••All Other Data: 1973-2006—U.S. Energy Information Administration (EIA), Natural Gas Annual, annual reports. 2007 forward—EIA, Natural Gas Monthly, March 2013, Table 1.

U.S. Energy Information Administration / Monthly Energy Review April 2013 69

112 d

110 b

2007-2008: (21,112-20,196) = .045=> 4.5%

20,196

2008-2009: (21,648-21,112) = .025=> 2.5%

21,112

2009-2010: (22,382-21,648) = .034=>3.4%

21,648

2010-2011: (24036-22382) = .073=> 7.3%

22382

2011-2012: (25298-24036) = .052=> 5.2%

24036

(4.5+2.5+3.4+7.3+5.2) = 4.6% average annual increase

5

Table 4.3 Natural Gas Consumption by Sector

(Billion Cubic Feet)

End-Use Sectors

Industrial Transportation

Other Industrial Pipelinesd Electric

Resi- Com- Lease and and Dis- Vehicle Power

dential merciala Plant Fuel CHPb Non-CHPc Total Total tributione Fuel Total Sectorf,g Total

1973 Total 4,879 2,597 1,496( h ) 8,689 8,689 10,185 728 NA 728 3,660 22,049

1975 Total 4,924 2,508 1,396( h ) 6,968 6,968 8,365 583 NA 583 3,158 19,538

1980 Total 4,752 2,611 1,026( h ) 7,172 7,172 8,198 635 NA 635 3,682 19,877

1985 Total 4,433 2,432 966( h ) 5,901 5,901 6,867 504 NA 504 3,044 17,281

1990 Total 4,391 2,623 1,236 1,055 i 5,963 i 7,018 8,255 660(s) 660 i 3,245 i 19,174

1995 Total 4,850 3,031 1,220 1,258 6,906 8,164 9,384 700 5 705 4,237 22,207

1996 Total 5,241 3,158 1,250 1,289 7,146 8,435 9,685 711 6 718 3,807 22,609

1997 Total 4,984 3,215 1,203 1,282 7,229 8,511 9,714 751 8 760 4,065 22,737

1998 Total 4,520 2,999 1,173 1,355 6,965 8,320 9,493 635 9 645 4,588 22,246

1999 Total 4,726 3,045 1,079 1,401 6,678 8,079 9,158 645 12 657 4,820 22,405

2000 Total 4,996 3,182 1,151 1,386 6,757 8,142 9,293 642 13 655 5,206 23,333

2001 Total 4,771 3,023 1,119 1,310 6,035 7,344 8,463 625 15 640 5,342 22,239

2002 Total 4,889 3,144 1,113 1,240 6,287 7,527 8,640 667 15 682 5,672 23,027

2003 Total 5,079 3,179 1,122 1,144 6,007 7,150 8,273 591 18 610 5,135 22,277

2004 Total 4,869 3,129 1,098 1,191 6,066 7,256 8,354 566 21 587 5,464 22,403

2005 Total 4,827 2,999 1,112 1,084 5,518 6,601 7,713 584 23 607 5,869 22,014

2006 Total 4,368 2,832 1,142 1,115 5,412 6,527 7,669 584 24 608 6,222 21,699

2007 Total 4,722 3,013 1,226 1,050 5,604 6,655 7,881 621 25 646 6,841 23,104

2008 Total 4,892 3,153 1,220 955 5,715 6,670 7,890 648 26 674 6,668 23,277

2009 Total 4,779 3,119 1,275 990 5,178 6,167 7,443 670 27 697 6,873 22,910

2010 Total 4,782 3,103 1,286 1,029 5,797 6,826 8,112 674 29 703 7,387 24,087

2011 January 970 528 107 90 563 652 759 82 3 85 540 2,882

February 769 432 97 81 513 594 691 70 2 72 484 2,448

March 601 364 111 82 526 608 719 63 3 66 482 2,232

April 347 236 109 83 479 562 670 51 3 54 521 1,828

May 208 168 112 87 468 555 667 46 3 49 572 1,663

June 135 135 107 88 440 527 635 46 3 48 699 1,653

July 111 128 110 97 438 535 644 52 3 55 939 1,877

August 109 135 111 99 446 546 657 52 3 55 921 1,878

September 122 141 109 91 451 541 651 46 3 48 684 1,646

October 227 208 116 85 479 563 680 48 3 51 575 1,741

November 429 283 115 86 501 587 701 56 3 59 543 2,014

December 686 397 118 96 539 635 753 71 3 74 614 2,524

Total 4,714 3,154 1,323 1,063 5,842 6,905 8,227 684 32 716 7,574 24,385

2012 January 802 448 E 118 98 555 653 771 E 77 E 3 E 80 648 2,750

February 668 391 E 109 90 521 612 721 E 70 E 3 E 73 648 2,500

March 408 263 E 117 90 507 597 713 E 60 E 3 E 62 677 2,124

April 284 211 E 114 87 482 570 683 E 55 E 3 E 58 720 1,956

May 165 151 E 118 93 472 565 683 E 52 E 3 E 55 817 1,871

June 125 133 E 113 94 462 557 670 E 52 E 3 E 55 885 1,867

July 109 126 E 118 101 464 564 682 E 58 E 3 E 61 1,093 2,071

August 107 135 E 117 98 478 576 693 E 56 E 3 E 59 1,007 2,001

September 119 142 E 115 93 471 564 679 E 50 E 3 E 53 807 1,800

October 241 212 E 119 95 497 591 711 E 53 E 3 E 56 671 1,892

November 481 305 E 116 97 513 610 726 E 60 E 3 E 63 578 2,154

December 668 388 E 118 103 539 642 760 E 69 E 3 E 72 585 2,472

Total 4,177 2,905 E 1,392 1,139 5,960 7,100 8,492 E 714 E 33 E 747 9,137 25,457

2013 January 881 478 E 117 102 573 675 792 E 80 E 3 E 83 629 2,864

a All commercial sector fuel use, including that at commercial combined-heat-and-power (CHP) and commercial electricity-only plants. See Table 7.4c for CHP fuel use. b Industrial combined-heat-and-power (CHP) and a small number of industrial electricity-only plants. c All industrial sector fuel use other than that in “Lease and Plant Fuel” and “CHP.” d Natural gas consumed in the operation of pipelines, primarily in compressors. e Natural gas used as fuel in the delivery of natural gas to consumers. f The electric power sector comprises electricity-only and combined-heat-and-power (CHP) plants within the NAICS 22 category whose primary business is to sell electricity, or electricity and heat, to the public. g Through 1988, data are for electric utilities only. Beginning in 1989, data are for electric utilities and independent power producers. h Included in “Non-CHP.” i For 1989-1992, a small amount of consumption at independent power producers may be counted in both “Other Industrial” and “Electric Power Sector.” See Note 7, “Natural Gas Consumption, 1989-1992,” at end of section.

E=Estimate. NA=Not available. (s)=Less than 500 million cubic feet.

Notes: Data are for natural gas, plus a small amount of supplemental

gaseous fuels. See Note 8, “Natural Gas Adjustments, 1993-2000,” at end of section. See Note, “Classification of Power Plants Into Energy-Use Sectors,” at end of Section 7. Totals may not equal sum of components due to independent rounding. Geographic coverage is the 50 States and the District of Columbia.

Web Page: See http://www.eia.gov/totalenergy/data/monthly/#naturalgas for all available data beginning in 1973.

Sources: Residential, Commercial, Lease and Plant Fuel, Other Industrial Total and Pipelines and Distribution: 1973-2006—U.S. Energy Information Administration (EIA), Natural Gas Annual (NGA), annual reports and unpublished revisions. 2007 forward—EIA, Natural Gas Monthly (NGM), March 2013, Table 2. Industrial CHP: Table 7.4c. Vehicle Fuel: 1990 and 1991—EIA, NGA 2000, (November 2001), Table 95. 1992-1998—EIA, “Alternatives to Traditional Transportation Fuels 1999” (October 1999), Table 10, and “Alternatives to Traditional Transportation Fuels 2003” (February 2004), Table 10. Data for compressed natural gas and liquefied natural gas in gasoline-equivalent gallons were converted to cubic feet by multiplying by the motor gasoline conversion factor (see Table A3) and dividing by the natural gas end-use sectors conversion factor (see Table A4). 1999-2006—EIA, NGA, annual reports. 2007 forward—EIA, NGM, March 2013, Table 2. Electric Power Sector: Table 7.4b.

U.S. Energy Information Administration / Monthly Energy Review April 2013

71

110d

110d

110g

110j (see below)

110 I (see below)

110 g

22,239 = 60.9 bcf/.

365

110 f

(69.7 – 60.9)

60.9 = 14449

=> 14.5%

110 h

25,457

365 = 697bcf/.

110 d

Electric power : 9137

25,457 = .359 => 36%

Transportation : 747

25,457 = .29 => 2.9%

Residential : 4,177

25,457 = .164 => 16.4%

Commercial : 2,905

25,457 = .114 => 11.4%

Industrial : 8492

25,457 = .334 => 33.4%

110 I (9137 – 5342)

5342 = .91 => 71%

110 j (4771 – 4177)

4771 = .1245 => 12.5%

Table 7.2a Electricity Net Generation: Total (All Sectors)

(Sum of Tables 7.2b and 7.2c; Million Kilowatthours)

Fossil Fuels Renewable Energy

Conven- Biomass

Hydro- tional

Nuclear electric Hydro-

Petro- Natural Other Electric Pumped electric Geo- Solar/

Coala leumb Gasc Gasesd Power Storagee Powerf Woodg Wasteh thermal PVi Wind Totalj

1973 Total 847,651 314,343 340,858 NA 83,479( f ) 275,431 130 198 1,966 NA NA 1,864,057

1975 Total 852,786 289,095 299,778 NA 172,505( f ) 303,153 18 174 3,246 NA NA 1,920,755

1980 Total 1,161,562 245,994 346,240 NA 251,116( f ) 279,182 275 158 5,073 NA NA 2,289,600

1985 Total 1,402,128 100,202 291,946 NA 383,691( f ) 284,311 743 640 9,325 11 6 2,473,002

1990 Total k 1,594,011 126,460 372,765 10,383 576,862 -3,508 292,866 32,522 13,260 15,434 367 2,789 3,037,827

1995 Total 1,709,426 74,554 496,058 13,870 673,402 -2,725 310,833 36,521 20,405 13,378 497 3,164 3,353,487

1996 Total 1,795,196 81,411 455,056 14,356 674,729 -3,088 347,162 36,800 20,911 14,329 521 3,234 3,444,188

1997 Total 1,845,016 92,555 479,399 13,351 628,644 -4,040 356,453 36,948 21,709 14,726 511 3,288 3,492,172

1998 Total 1,873,516 128,800 531,257 13,492 673,702 -4,467 323,336 36,338 22,448 14,774 502 3,026 3,620,295

1999 Total 1,881,087 118,061 556,396 14,126 728,254 -6,097 319,536 37,041 22,572 14,827 495 4,488 3,694,810

2000 Total 1,966,265 111,221 601,038 13,955 753,893 -5,539 275,573 37,595 23,131 14,093 493 5,593 3,802,105

2001 Total 1,903,956 124,880 639,129 9,039 768,826 -8,823 216,961 35,200 14,548 13,741 543 6,737 3,736,644

2002 Total 1,933,130 94,567 691,006 11,463 780,064 -8,743 264,329 38,665 15,044 14,491 555 10,354 3,858,452

2003 Total 1,973,737 119,406 649,908 15,600 763,733 -8,535 275,806 37,529 15,812 14,424 534 11,187 3,883,185

2004 Total 1,978,301 121,145 710,100 15,252 788,528 -8,488 268,417 38,117 15,421 14,811 575 14,144 3,970,555

2005 Total 2,012,873 122,225 760,960 13,464 781,986 -6,558 270,321 38,856 15,420 14,692 550 17,811 4,055,423

2006 Total 1,990,511 64,166 816,441 14,177 787,219 -6,558 289,246 38,762 16,099 14,568 508 26,589 4,064,702

2007 Total 2,016,456 65,739 896,590 13,453 806,425 -6,896 247,510 39,014 16,525 14,637 612 34,450 4,156,745

2008 Total 1,985,801 46,243 882,981 11,707 806,208 -6,288 254,831 37,300 17,734 14,840 864 55,363 4,119,388

2009 Total 1,755,904 38,937 920,979 10,632 798,855 -4,627 273,445 36,050 18,443 15,009 891 73,886 3,950,331

2010 Total 1,847,290 37,061 987,697 11,313 806,968 -5,501 260,203 37,172 18,917 15,219 1,212 94,652 4,125,060

2011 January 170,803 3,457 74,254 930 72,743 -426 25,531 3,290 1,515 1,347 40 8,550 363,105

February 138,311 2,434 65,924 807 64,789 -247 24,131 2,937 1,427 1,215 85 10,452 313,293

March 134,845 2,692 65,947 945 65,662 -349 31,134 3,081 1,565 1,337 122 10,545 318,710

April 124,488 2,424 70,029 918 54,547 -466 31,194 2,798 1,503 1,239 164 12,422 302,400

May 137,102 2,378 75,243 875 57,013 -418 32,587 2,794 1,563 1,318 191 11,772 323,627

June 158,055 2,594 90,691 1,013 65,270 -567 32,151 3,230 1,632 1,215 223 10,985 367,727

July 176,586 3,154 119,624 1,098 72,345 -708 31,285 3,362 1,690 1,269 191 7,489 418,693

August 171,281 2,594 119,856 1,087 71,339 -663 25,764 3,384 1,692 1,275 229 7,474 406,541

September 140,941 2,424 91,739 1,004 66,849 -553 21,378 3,178 1,589 1,226 186 6,869 337,961

October 126,627 2,062 78,819 941 63,337 -572 19,787 2,954 1,631 1,281 159 10,525 308,727

November 121,463 1,783 75,441 943 64,474 -441 20,681 3,088 1,684 1,271 107 12,439 304,119

December 132,929 2,186 86,122 1,005 71,837 -496 23,732 3,353 1,731 1,324 121 10,656 335,753

Total 1,733,430 30,182 1,013,689 11,566 790,204 -5,905 319,355 37,449 19,222 15,316 1,818 120,177 4,100,656

2012 January 129,115 2,444 91,641 980 72,381 -330 23,359 3,366 1,629 1,415 86 13,806 340,919

February 113,908 1,926 91,091 1,005 63,847 -226 20,361 3,126 1,537 1,339 137 11,164 310,151

March 105,546 1,561 92,503 1,010 61,729 -268 25,770 2,938 1,663 1,413 249 13,897 309,040

April 96,466 1,564 95,346 980 55,871 -242 26,136 2,666 1,668 1,335 346 12,812 295,940

May 116,345 1,727 107,927 969 62,081 -343 28,542 2,997 1,713 1,422 511 12,573 337,530

June 131,569 2,056 116,015 945 65,140 -475 26,611 3,060 1,687 1,380 561 11,944 361,506

July 160,938 2,288 140,202 968 69,129 -587 26,758 3,296 1,769 1,421 522 8,724 416,515

August 152,743 2,072 131,828 1,024 69,602 -496 23,146 3,311 1,676 1,388 464 8,287 396,108

September 125,767 1,864 108,206 893 64,511 -401 17,562 3,143 1,628 1,377 462 8,680 334,735

October 121,587 1,861 92,141 820 59,743 -351 16,207 3,073 1,660 1,413 431 12,514 312,157

November 128,992 1,779 79,707 759 56,713 -390 18,834 3,216 1,633 1,429 314 11,513 305,548

December 134,230 1,757 84,103 858 68,584 -549 23,248 3,350 1,762 1,459 258 14,175 334,335

Total 1,517,203 22,900 1,230,708 11,212 769,331 -4,658 276,535 37,540 20,025 16,791 4,342 140,089 4,054,485

2013 January 138,447 2,669 88,375 919 71,406 -442 25,123 3,299 1,587 1,444 288 14,535 348,642

a Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and coal synfuel. b Distillate fuel oil, residual fuel oil, petroleum coke, jet fuel, kerosene, other petroleum, waste oil, and, beginning in 2011, propane. c Natural gas, plus a small amount of supplemental gaseous fuels. d Blast furnace gas, and other manufactured and waste gases derived from fossil fuels. Through 2010, also includes propane gas. e Pumped storage facility production minus energy used for pumping. f Through 1989, hydroelectric pumped storage is included in “Conventional Hydroelectric Power.” g Wood and wood-derived fuels. h Municipal solid waste from biogenic sources, landfill gas, sludge waste, agricultural byproducts, and other biomass. Through 2000, also includes non-renewable waste (municipal solid waste from non-biogenic sources, and tire-derived fuels).

i Solar thermal and photovoltaic (PV) energy. j Includes batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, miscellaneous technologies, and, beginning in 2001, non-renewable waste (municipal solid waste from non-biogenic sources, and tire-derived fuels). k Through 1988, all data except hydroelectric are for electric utilities only; hydroelectric data through 1988 include industrial plants as well as electric utilities. Beginning in 1989, data are for electric utilities, independent power producers, commercial plants, and industrial plants.

NA=Not available.

Notes: •••Totals may not equal sum of components due to independent rounding. •••Geographic coverage is the 50 States and the District of Columbia.

Web Page: See http://www.eia.gov/totalenergy/data/monthly/#electricity for all available data beginning in 1973.

Sources: See sources for Tables 7.2b and 7.2c.

U.S. Energy Information Administration / Monthly Energy Review April 2013 95

110 E

110 E

Renewables: (276,535 + 37,540 + 20,025 + 16,791 + 4,342 + 140,089) = .1221 = > 12.2%

4,054,485

Natural Gas: 1,230,708

4,054,485 = .3035= >30.4%

Coal: 1,517,203 = .3742= >37.4%

4,054,485

(petroleum) (other gases)

Other: 22,900 + 11212

4,054,485 = .0084 = .8%

Nuclear : 769,331 = .18697 => 19%

4,054,485

DOE/EIA-0383(2012) | June 2012

Annual Energy Outlook 2012

with Projections to 2035

Independent Statistics &.Analysis

U.S. Energy Information Administration

U.S. Energy Information Administration | Natural Gas Annual 1

Natural gas production

Shale gas provides largest source of growth in U.S. natural gas supply

Figure 107. Natural gas production by source, 1990-2035 (trillion cubic feet)

In most U.S. regions, natural gas production growth is led by shale gas development

Figure 108. Lower 48 onshore natural gas production by region, 2010 and 2035 (trillion cubic feet)

U.S. Energy Information Administration | Natural Gas Annual 1

IBB

Shale gas

Tight gas

Lower -I8 onshore con

Alaska Lower 48 offshore

Coalbed methane

The increase in natural gas production from 2010 to 2035 in the AE02012 Reference case results primarily from the continued development of shale gas resources (Figure 107). Shale gas is the largest contributor to production growth; there is relatively little change in production levels from tight formations, coalbed methane deposits, and offshore fields.

Shale gas accounts for 49 percent of total U.S. natural gas pro-duction in 2035, more than double its 23-percent share in 2010. In the Reference case, estimated proved and unproved shale gas resources amount to a combined 542 trillion cubic feet, out

of a total U.S. resource of 2,203 trillion cubic feet. Estimates of shale gas resources and well productivity remain uncertain (see “Issues in focus” for discussion).

Tight gas produced from low permeability sandstone and car¬bonate reservoirs is the second-largest source of domestic supply in the Reference case, averaging 6.1 trillion cubic feet of production per year from 2010 to 2035. Coalbed methane pro¬duction remains relatively constant throughout the projection, averaging 1.8 trillion cubic feet per year.

Offshore natural gas production declines by 0.8 trillion cubic feet from 2010 through 2014, following the 2010 moratorium on offshore drilling, as exploration and development activities in the Gulf of Mexico focus on oil-directed activity. After 2014 offshore production continues to rise throughout the remainder of the projection period.

Shale gas production, which more than doubles from 2010 to 2035, is the largest contributor to the projected growth in total U.S. natural gas production in the Reference case. Regional pro¬duction growth largely reflects expected increases in produc¬tion from shale beds. See Figure F4 in Appendix F for a map of U.S. natural gas supply regions.

In the Northeast, natural gas production grows by an aver¬age of 5.2 percent per year, or a total of 3.9 trillion cubic feet from 2010 to 2035 (Figure 108). The Marcellus shale, which accounts for 3.0 trillion cubic feet of the expected increase, is particularly attractive for development because of its large resource base, its proximity to major natural gas consumption markets, and the extensive pipeline infrastructure that already exists in the Northeast.

In the Gulf Coast region, natural gas production grows by 2.0 trillion cubic feet from 2010 to 2035, at an average rate of 1.4 percent per year. Natural gas production from the Haynesville/ Bossier and Eagle Ford formations increases by 2.8 trillion cubic feet over the period, but declines in production from other nat¬ural gas fields in the region offset some of the gains, so that the net increase in production for the region as a whole is only about 2 trillion cubic feet.

In the Rocky Mountain region, natural gas production grows by 0.9 trillion cubic feet from 2010 through 2035, with tight sand¬stone and carbonate production increasing by 0.8 trillion cubic feet and shale gas production by 0.4 trillion cubic feet. As in the Gulf Coast region, production growth in the Rocky Mountain region is offset in part by production declines in the region’s other natural gas fields.

Shale gas provides the largest source of growth in U.S. natural gas supply

Figure 91. Natural gas production by source, 1990-2040 (trillion cubic feet)

Pipeline exports increase as Canadian imports fall and exports to Mexico rise

Figure 92. U.S. net imports of natural gas by source, 1990-2040 (trillion cubic feet)

Alaska Shale gas Tight gas

Lower 48 onshore conventional

lower 43 offshore Coalbed methane

30

20

10

History

2011

Projections

2000

2010

2020

2030

1990

History 2011 Projections

4

^ Mexico ^

-3 I F T* “I 1 1

1990 2000 2010 2020 2030 2040

The 44-percent increase in total natural gas production from 2011 through 2040 in the AE02013 Reference case results from the increased development of shale gas, tight gas, and coalbed methane resources (Figure 91). Shale gas production, which grows by 113 percent from 2011 to 2040, is the greatest contrib¬utor to natural gas production growth. Its share of total oroduc- tion increases from] 34 percent in 2011 to 50 percent in 2040. \ Tight gas and coalbed methane production aIso increase,by 25 percent and 24 percent, respectively, from 2011 to 2040, even as their shares of total production decline slightly. The growth in coalbed methane production is not realized until after 2035, when natural gas prices and demand levels are high enough to spur more drilling.

Offshore natural gas production declines by 0.3 trillion cubic feet from 2011 through 2014, as offshore exploration and devel¬opment activities are directed toward oil-prone areas in the Gulf of Mexico. After 2014, offshore natural gas production recov¬ers as prices rise, growing to 2.8 trillion cubic feet in 2040. As a result, from 2011 to 2040, offshore natural gas production increases by 35 percent.

Alaska natural gas production also increases in the Reference case with the advent of Alaska LNG exports to overseas cus¬tomers beginning in 2024 and growing to 0.8 trillion cubic feet per year (2.2 billion cubic feet per day) in 2027. In 2040, Alaska natural gas production totals 1.2 trillion cubic feet.

Although total U.S. natural gas production rises throughout the projection, onshore nonassociated conventional production declines from 3.6 trillion cubic feet in 2011 to 1.9 trillion cubic feet in 2040, when it accounts for only about 6 percent of total domestic production, down from 16 percent in 2011.

With relatively low natural gas prices in the AE02013 Reference case, the United States becomes a net exporter of natural gas in 2020, and net exports grow to 3.6 trillion cubic feet in 2040 (Figure 92). Most of the projected growth in U.S. exports con¬sists of pipeline exports to Mexico, which increase steadily over the projection period, as increasing volumes of imported natural gas from the United States fill the growing gap between Mexico’s production and consumption. Exports to Mexico increase from 0.5 trillion cubic feet in 2011 to 2.4 trillion cubic feet in 2040.

U.S. exports of domestically sourced LNG (excluding existing exports from the Kenai facility in Alaska, which fall to zero in 2013) begin in 2016 and rise to a level of 1.6 trillion cubic feet per year in 2027. One-half of the projected increase in U.S. exports of LNG originate in the Lower 48 states and the other half from Alaska. Continued low levels of LNG imports through the pro¬jection period position the United States as a net exporter of LNG by 2016. In general, future U.S. exports of LNG depend on a number of factors that are difficult to anticipate, including the speed and extent of price convergence in global natural gas markets, the extent to which natural gas competes with oil in domestic and international markets, and the pace of natural gas supply growth outside the United States.

Net natural gas imports from Canada decline sharply from 2016 to 2022, then stabilize somewhat before dropping off again in the final years of the projection, as continued growth in domes¬tic production mitigates the need for imports. Even as overall consumption exceeds supply in the United States, some natural gas imports from Canada continue, based on regional supply and demand conditions.

Ql/^‘OOW 2-0

Figure 91. Natural gas production by source, 1990-2040 (trillion cubic feet)

Lower 48

Coalbed Lower 48 Onshore Tight Shale

Alaska Methane Offshore Conventional gas Gas

1990 0.38 0.27 5.33 9.50 2.13 0.20

1991 0.41 0.35 5.08 9.32 2.38 0.15

1992 0.41 0.56 4.95 9.60 2.15 0.17

1993 0.40 0.75 5.09 9.22 2.42 0.22

1994 0.52 0.86 5.39 9.50 2.32 0.23

1995 0.43 0.96 5.33 9.02 2.58 0.28

1996 0.44 1.11 5.53 8.06 3.55 0.16

1997 0.43 1.18 5.51 7.89 3.66 0.24

1998 0.43 1.31 5.45 7.73 3.85 0.26

1999 0.42 1.39 5.37 7.60 3.78 0.27

2000 0.42 1.51 5.17 7.73 4.03 0.32

2001 0.44 1.60 5.33 7.63 4.25 0.36

2002 0.43 1.65 4.75 7.21 4.44 0.45

2003 0.46 1.70 4.76 6.97 4.68 0.52

2004 0.44 1.72 4.22 6.52 5.09 0.60

2005 0.46 1.73 3.37 6.32 5.43 0.75

2006 0.42 1.76 3.10 6.40 5.82 1.00

2007 0.41 1.78 2.98 6.34 6.26 1.50

2008 0.37 1.99 2.68 6.44 6.43 2.25

2009 0.37 1.72 2.70 5.55 6.80 3.47

2010 0.35 1.69 2.44 5.65 6.34 4.86

2011 0.35 1.71 2.11 5.12 5.86 7.85

2012 0.32 1.67 2.19 5.83 5.76 8.13

2013 0.31 1.69 1.92 5.59 5.89 8.60

2014 0.30 1.67 1.83 5.54 5.85 8.66

2015 0.30 1.64 1.89 5.50 5.85 8.85

2016 0.29 1.70 2.09 5.60 6.08 9.37

2017 0.29 1.71 2.03 5.38 6.21 9.79

2018 0.29 1.73 2.03 5.29 6.31 ####

2019 0.28 1.73 2.05 5.17 6.37 ####

2020 0.28 1.71 2.07 5.11 6.40 ####

2021 0.27 1.70 2.12 5.04 6.44 ####

2022 0.27 1.70 2.20 4.97 6.49 ####

2023 0.27 1.69 2.22 4.86 6.54 ####

2024 0.50 1.67 2.18 4.73 6.56 ####

2025 0.73 1.66 2.19 4.60 6.56 ####

2026 0.97 1.67 2.19 4.43 6.59 ####

2027 1.20 1.67 2.25 4.23 6.61 ####

2028 1.20 1.68 2.26 4.06 6.61 ####

2029 1.19 1.69 2.29 3.86 6.65 ####

2030 1.19 1.69 2.34 3.74 6.67 ####

2031 1.19 1.69 2.42 3.65 6.71 ####

40

30

i

jShaiegjs

Tight gas

Lower 46 onshore conventional

Alaska lamt 48 offshore

Coaibed methane^

2032 1.19 1.70 2.57 3.57 6.75 ####

2033 1.19 1.70 2.72 3.50 6.79 ####

2034 1.18 1.71 2.76 3.42 6.87 ####

2035 1.18 1.73 2.81 3.33 6.96 ####

2036 1.18 1.78 2.71 3.25 7.07 ####

2037 1.18 1.87 2.60 3.17 7.16 ####

2038 1.18 1.96 2.59 3.09 7.23 ####

2039 1.18 2.04 2.78 3.01 7.28 ####

2040 1.18 2.11 2.85 2.96 7.34 ####

Table A2. Energy consumption by sector and source (continued)

(quadrillion Btu per year, unless otherwise noted)

Sector and source Reference ease Annual

growth

2011-2040

(percent)

2010 2011 2020 2025 2030 2035 2040

Total energy consumption

Liquefied petroleum gases 2.83 2.82 3.21 3.29 3.23 3.16 3.08 0.3%

Propylene 0.41 0.40 0.56 0.56 0.52 0.49 0.46 0.6%

E85a 0.01 0.05 0.08 0.14 0.16 0.15 0.17 4.3%

Motor gasoline2 17.13 16.64 15.26 14.24 13.43 13.07 13.03 -0.8%

Jet fuel* 3.07 3.01 3.11 3.20 3.28 3.35 3.42 0.4%

Kerosene 0.04 0.03 0.03 0.03 0.02 0.02 0.02 -0.3%

Distillate fuel oil S.08 8.18 9.43 9.57 9.59 9.66 9.82 0.6%

Residual fuel oil 1.38 1.24 1.15 1.15 1.15 1.16 1.17 -0.2%

Petrochemical feedstocks 0.94 0.88 1.03 1.08 1.08 1.08 1.09 0.7%

Other petroleum15 3.86 3.77 3.69 3.63 3.61 3.68 3.80 0.0%

Liquid fuels and other petroleum subtotal 37.76 37.02 37.54 36.87 36.08 35.82 36.07 -0.1%

Natural gas . 22.32 22.79 24.36 24.71 25.27 26.18 26.75 0.6%

Natural-gas-to-liquids heat and power 0.00 0.00 0.13 0.16 0.21 0.27 0.33 —

Lease and plant fuel5 1.31 1.42 1.57 1.68 1.73 1.84 1.97 1.1%

Pipeline natural gas 0.68 0.70 0.71 0.73 0.74 0.76 0.78 0.4%

Natural gas subtotal 24.32 24.91 26.77 27.28 27.95 29.06 29.83 0.6%

Metallurgical coal 0.55 0.56 0.60 0.58 0.52 0.48 0.46 -0.7%

Other coal 20.26 19.09 18.01 18.72 19.12 19.55 19.79 0.1%

Coal-to-liquids heat and power 0.00 0.00 0.00 0.07 0.09 0.12 0.15 —

Net coal coke Imparts -0.01 0.01 -0.01 -0.03 -0.04 -0.06 -0.05 —

Coal subtotal 20.81 19.66 18.59 19.35 19.70 20.09 20.35 0.1%

Nuclear /uranium15 8.43 8.26 9.25 9.54 9.49 9.14 9.44 0.5%

Blofuels heat and coproducts 0.85 0.67 0.82 0.82 0.85 0.97 1.37 2.5%

Renewable energy18 5.86 6.82 7.77 8.18 8.47 9.07 10.30 1.4%

Liquid hydrogen 0.00 0.00 0.00 0.00 0.00 0.00 0.00 —

Electricity Imports 0.09 0.13 n(M nm am nm nnfi -2.4%

Total 98.35 \ 97.70 101.04 . 1Q2.34. 102 ill. —10*^1 107.64 \0.3%

Energy use and related statistics -7, ~j —Aon-z I0^° o j

Delivered energy use 71.49 71.01 74.01 74.40 74.38 75.41 77.63 0.3%

Total energy use 98.35 97.70 101.04 102.34 102.81 104.41 107.64 0.3%

Ethanol consumed In motor gasoline and E85 1.11 1.17 1.34 1.29 1.24 1.20 1.21 0.1%

Population (millions) 310.06 312.38 340.45 356.46 372.41 388.35 404.39 0.9%

Gross domestic product (bDIion 2005 dollars) 13,063 13,299 16,859 18,985 21,355 24,095 27,277 2.5%

Carbon dioxide emissions (million metric tons), 5,633.6 5,470.7 5,454.6 5,501.4 5,522.8 5,606.7 5,691.1 0.1%

[HOC

Indudes wood used for residential heating. See Table A4 and/or Table A17 for estimates of nonmarketed renewable energy consumption for geothermal heat pumps, solar thermal water heating, and electricity generation from wind and solar photovoltaic sources.

nndudes ethanol (blends of 15 percent or less) and ethers blended Into gasoline.

*Exdudes ethanol. Indudes commercial sector consumption of wood and wood waste, landfill gas, municipal waste, and other biomass for combined heat and power. See Table A5 and/or Table A17 for estimates of nonmarketed renewable energy consumption for solar thermal water heating and electricity generation from wind and solar photovoltaic sources.

“Includes energy for combined heat and power plants that have a non-regulatory status, and small on-site generating systems.

•includes petroleum coke, asphalt road ofl. lubricants, still gas, and miscellaneous petroleum products.

•Represents natural gas used in wsfl, fiekJ, and tease operations, in natural gas processing plant machinery, and for liquefaction in export facilities.

Includes consumption of energy produced from hydroelectric, wood and wood waste, municipal waste, and other biomass sources. Excludes ethanol blends (15 percent or less) in motor gascune.

*E85 refers to a Wend of 55 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). To address cold starting issues, the percentage of ethanol varies seasonally. The annual average ethanol content of 74 percent is used for this forecast.

•includes only kerosene ta>e.

’“Diesel fuel for orv and off- road use.

Indudes aviation gasoline and lubricants.

13Indudes unfinished oils, natural gasoline, motor gasoline Mending components, aviation gasoline, lubricants, stlD gas, asphalt, road oil, petroleum coke, and miscellaneous petroleum products.

Tndudes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Exdudes ethanol and nonmarketed renewable energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal water heaters.

11ndudes consumption of energy by electridty-onfy and combined heat and power plants that have a regulatory status.

1*These values represent the energy obtained from uranium when it is used in Dght water reactors. The total energy content of uranium is much larger, but alternative processes are required to take advantage of it

“Includes conventional hydroelectric, geothermal, wood and wood waste, biogenic municipal waste, other biomass, wind, photovoltaic, and solar thermal sources. Exdudes net etectndty imports.

“Includes non-btogenic murtidpa) waste not included above.

Indudea conventional hydroelectric, geothermal, wood and wood waste, biogenic munidpai waste, other biomass, wind, photovoltaic, and solar thermal sources. Excludes ethanol, net electricity imports, and nonmarketed renewable energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal water heaters.

Btu « British thermal unit

— = Not applicable.

Note: Totals may not equal sum of components due to Independent rounding. Data for 2010 and 2011 are model results and may differ slightly from official EIA data reports.

Sources: 2010 and 2011 consumption based on: U.S. Energy Information Administration (EIA), Annual Energy Review 2011, DOE/EIA-0384{2011)

emissions: EIA, Monthly Energy Review, DOE7EIA-0035(2011/10) (Washington, DC, October 2011). 2011 carbon dioxide emissions: EIA, Monthly & Review, DOE/EIA-0035(2012/08) (Washington, DC, August 2012). Projections: EIA, AEQ2013 National Energy Modeling System run REF2013.D102312A.    

Table A13. Natural gas supply, disposition, and prices

(trillion cubic feet per year, unless otherwise noted)

Supply, disposition, and prices Reference case Annual

growth

2010 2011 2020 2025 2030 2035 2040 2011-2040

(percent)

Supply

Dry gas production’ 21.33 23.00 26.61 28.59 29.79 31.35 33.14 1.3%

Supplemental natural gas2 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.2%

Net imports 2.60 1.95 -0.14 -1.58 -2.10 -2.55 -3.55 —

Pipeline3 2.24 1.67 0.13 -0.52 -0.67 -1.09 -2.09 —

Liquefied natural gas 0.37 0.28 -0.26 -1.06 -1.43 -1.46 -1.46 —

Total supply.—24.00 25.01 26.54 27.07 27.75 28.86 29.65 0.6%

Consumption by sector

Residential 4.78 4.72 4.52 4.44 4.36 4.24 4.14 -0.5%

Commercial 3.10 3.16 3.32 3.35 3.42 3.51 3.60 0.4%

Industrial4 6.52 6.77 7.68 7.82 7.79 7.84 7.90 0.5%

Naturai-gas-to-ilqulds heat and power3 0.00 0.00 0.13 0.16 0.21 0.26 0.33 —

Natural gas to liquids production” 0.00 0.00 0.14 0.17 0.22 0.28 0.35 —

Electric power7 7.39 7.60 8.23 8.45 8.89 9.44 9.50 0.8%

Transportation* 0.04 0.04 0.08 0.12 0.26 0.59 1.04 11.9%

Pipeline fUel 0.67 0.68 0.70 0.71 0.73 0.74 0.76 0.4%

1.28 1 39 1.54 1.64 1.70 1 81 1 93 I o.™|

Total consumption- 23.78 24.37 26.32 26.87 27.57 28.71 | 29.54

Discrepancy10 — 0.22 0.64 0.22 0.20 0.18 0.15 0.12 —

Natural gas spot price at Henry Hub

(2011 dollars per million Btu) 4.46 3.98 4.13 4.87 5.40 6.32 7.83 2.4%

(nominal dollars per million Btu) 4.37 3.98 4.77 6.14 7.45 9.55 12.92 4.1%

Delivered natural gas prices (2011 dollars per thousand cubic feet)

Residential 11.62 11.05 12.05 12.97 13.68 14.93 16.74 1.4%

Commercial 9.61 9.04 9.69 10.43 10.94 11.95 13.52 1.4%

Industrial4 5.61 5.00 5.66 6.29 6.71 7.62 9.09 2.1%

Electric power7 5.37 4.87 5.00 5.70 6.18 7.13 8.55 2.0%

Transportation11 16.89 16.51 17.26 18.39 19.34 20.31 21.68 0.9%

Average12 7.44 6.83 7.23 7.93 8.45 9.51 11.18 1.7%

(nominal dollars per thousand cubic feet)

Residential 11.38 11.05 13.89 16.34 18.87 22.57 27.63 3.2%

Commercial 9.41 9.04 11,17 13.14 15.10 18.06 22.31 3.2%

Industrial4 5.49 5.00 6.52 7.93 9.26 11.51 14.99 3.9%

Electric power7 5.26 4.87 5.76 7.18 8.53 10.77 14.12 3.7%

Transportation11 16.54 16.51 19.90 23.17 26.68 30.70 35.79 2.7%

Average12 7.28 6.83 8.34 9.99 11.66 14.37 18.46 3.5%

G£3

1 Marketed production (wet) minus extraction losses.

aSyntheU^na^railjpa3, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingted and

“HSSU any naturafgaa regaslfied in the Bahamas and transported via pipeline to Florida, as well as gas from Canada and Mexico.

*1ndudes energy for combined heat and power plants that have a non-regulatory status, and small on-site generating systems.

‘Includes any natural gas used in the process of converting natural gas to liquid fud that Is not actually converted.

Includes any natural gas converted Into liquid fuel.

7lndudes consumption of energy by electricity-only and combined heat and power plants that have a regulatory status.

“Natural gas used as vehicle fuel.

Represents natural gas used In well, field, and lease operations, In natural gas processing piant machinery, and for liquefaction In export facilities.

“Balancing Item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 2010 and 2011 values include net

merger of

injections.

Natural gas used as a vehicle fuel. Price Indudes

prices. Weights used are the sectoral consumption values excluding lease, plant.

may not equal sum of components due to Independent rounding. Data for 2010 and 2011 are model results and may differ sightly from official EIA

Sources: 2010 supply values; lease, plant, and pipeline fuel consumption; and residential, commercial, and industrial delivered prices:

Information Administration (EIA), Natural Gas Annual 2010, DOE/EiA-0131(2010) (Washington, DC, December 2011V 2011 ! pipeline fuel consumption; and residential, commercial, and Industrial delivered prices: EIA, Natural Gas Monthly, DOE/EIA-O13<

21312). Other 2010 and 2011 consumption based on: EIA, Annual Energy Review 2011, DOE;EIA-0384(201 i) (Washington, I 2011 natural gas price at Henry Hub based on daily spot prices published bi Natural Gas Intelligence. 2010 and 2011 electric power prices: EIA, I Monthly. DOE/h£o226, April 2011 and Apr* 2012, Table 4.2, and EIA, Sfats Energy Data Report 2010, DOE/EI*0214(2Q10) (Washington, DC, June 2012). 2010 transportation sector delivered prices are based on: EIA, Natural Gas Annuel 2010, DQE/E1A-0131(2010) (Washington, DC, December 2011 land estimated state taxes, federal taxes, and dispensing costs or charges. 2011 transportation sector delivered prices are model results. Protections: EIA, AEQ2013 National Energy Modeling System run REF2013.D102312A.

Independent Statistics & Analysis

U.S. Energy Information Administration

Natural Gas Annual

2011

A

2011

Table 1. Summary statistics for natural gas in the United States, 2007-2011

^

19,266,026 20,158,602 20,623,854

“13,247,498

“5,834,703

1,916,762

5,817,122

*i4,414,287

“5,674,120

“2,010,171

“15,134,644

12,291,070

5,907,919

1,779,055

8,500,983

“14,991,891

“5,681,871

“1,999,748

1,990,145

24,663,656

3,662,685

143,457

661,168

20,196,346

930,320

>5,609,425

“2,022,228

3,365,313

2(59)439

867,922

24,036,352

1.134/473

22,901,379

21,315,507

3,740,757

316,400

3,274,385

“36,487

64,575

“124,358

“28,872/470

22,901,879

3,468,693

110,740

3,074,251

33,739

27371385 28,037,750 27,653,447 “28,872,470 29,427,972

861,063 864,113 913,229 916,797

“674,124 938,340

683,715

621,364 647,956 670,174

365,323 355,590 362,009 “368,830 384,248

60,088

-221,419

4,722358

3,012,904

6,654,716

444,010*fe5i,116519,466

1,273,058

5,008,265

550329

1,394,268

5,757,480

“1,317,138

“5,651,037

1,132,106

5,178,329

“4,782,412

“3,102,593

“6,826,192

“28,664

7,387,184

491,940

1,201,169

5,307,954

“22,127,046

“24,086,797

24,655 4,892,277

3,152,529

6,670,182

25,982 4,778,907

3,118,592

6,167,371

27,262

6,841,408 6,668,379 6,872333

21,256,042 21,409,349 20,964,665

23,103,793 23,277,008 22310,078

29,427,972

4,713,695

3,153,605

6,904,843

32,247

7,573,863

22378,253

24384356

24,384,556

1,507,058

74,231

3,421,813

40,313

“2,869,960

25,636,257

3,638,622

166,909

718,674

21,112,053

953,451

“3,95B,315

26,056,893

3,522,090

165,360

721,507

21,647,936

1,024,082

“26,816,085

3,431,587

165,928

836,698

“22,3817873

“1,066,366

“21,315,507

4.6073B2

455,690 3,984,101

380,986 3,751,360

294,790

3325,013

50,167

63,132

-196,323 3,374,338

45,362

60,889

33,472 2,966,278

41,298

65,259

-89,392

27,571385 28,037,750 27,653,447

23,103,793 23,277,008 22,910,078

822,454 963,263 1,072357

461,939 412,055 308,919

3,132,920

50,180 37340365

45,060 3,314,997

47,096

Number of Wells Producing at End of Year

Production (million cubic feet)

Gross Withdrawals From Gas Wells From Oil Wells From Coalbed Wells From Shale Gas Wells

Total

Repressurlng Vented and Flared Nonhydrocarbon Gases Removed Marketed Production Extraction Loss

Total Dry Production

Supply (million cubic feet)

Dry Production Receipts at U.S. Borders Imports

Intransit Receipts Withdrawals from Storage Underground Storage LNG Storage

Supplemental Gas Supplies Balancing item

Total Supply

Disposition (million cubic feet)

Consumption Deliveries at U.S. Borders Exports

Intranslt Deliveries Additions to Storage Underground Storage LNG 5torage

Total Disposition

Consumption (million cubic feet)

Lease Fuel

Pipeline and Distribution Use*

Plant Fuel

Delivered to Consumers Residential Commercial Industrial Vehicle Fuel Efectric Power

Total Delivered to Consumers

Total Consumption

Delivered for the Account of Others (million cubic feet)

Resldentlaf

Commercial

Industrial

See footnotes of end of table.

U.S. Energy Information Administration | Natural Gas Annual1