10-K 1 vnr-20141231x10k.htm VNR-2014 12 31-10K



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
(Mark One)
 
 
ý
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the fiscal year ended December 31, 2014
 
 
 
Or
 
 
 
p
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the transition period from          to          .
 
Commission File Number 001-33756
 
Vanguard Natural Resources, LLC
(Exact Name of Registrant as Specified in Its Charter)
 
Delaware
 
61-1521161
(State or Other Jurisdiction of
 Incorporation or Organization)
 
(I.R.S. Employer
 Identification No.)
 
 
 
5847  San Felipe, Suite 3000
 Houston, Texas
 
77057
(Address of Principal Executive Offices)
 
(Zip Code)
 
Telephone Number: (832) 327-2255
Securities registered pursuant to Section 12(b) of the Act:
 
Title of Each Class
 
Name of Each Exchange
 on which Registered
 
 
 
Common Units
 
The NASDAQ Global Select Market
7.875% Series A Cumulative Redeemable Perpetual Preferred Units
 
The NASDAQ Global Select Market
7.625% Series B Cumulative Redeemable Perpetual Preferred Units
 
The NASDAQ Global Select Market
7.75% Series C Cumulative Redeemable Perpetual Preferred Units
 
The NASDAQ Global Select Market
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
 
 
Yes x
 
No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
 
 
Yes o
 
No x
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
 
Yes x
 
No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
 
 
Yes x
 
No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
 
 
 
 
o  
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
 
Accelerated filer o
Non-accelerated filer o
 
Smaller reporting company o
(Do not check if smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
 
 
Yes o
 
No x
 
The aggregate market value of Vanguard Natural Resources, LLC common units held by non-affiliates of the registrant as of June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $2,599,585,338 based upon the closing price reported for such date on the NASDAQ Global Select Market.
 
As of February 25, 2015, 83,709,271 of the registrant’s common units remained outstanding.
 
Documents Incorporated by Reference:
Portions of the registrant’s proxy statement to be furnished to unitholders in connection with its 2015 Annual Meeting of Unitholders are incorporated by reference in Part IIIItems 10-14 of this annual report on Form 10-K for the year ending December 31, 2014 (this “Annual Report”). Such proxy statement will be filed with the Securities and Exchange Commission within 120 days of the registrant’s fiscal year ended December 31, 2014.


 





Vanguard Natural Resources, LLC

TABLE OF CONTENTS
 
 
Caption
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 





Forward-Looking Statements
 
Certain statements and information in this Annual Report may constitute “forward-looking statements.”  The words “may,” “will,” estimate,” “predict,” “potential,” “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature.  These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections.  Known material factors and other factors that could cause our actual results to differ from those in our forward-looking statements are those described in “Item 1A. Risk Factors” and those described elsewhere in this Annual Report. Factors that could affect our actual results and could cause actual results to differ materially from those in our forward-looking statements include, but are not limited to, the following:

the volatility of realized oil, natural gas and NGLs prices, including the recent declines in such prices;
the potential for additional impairment due to continuing or future declines in oil, natural gas and NGLs prices;
uncertainties about the estimated quantities of oil, natural gas and NGLs reserves, including uncertainties about the effects of the SEC’s rules governing reserve reporting;
the conditions of the capital markets, liquidity, general economic conditions, interest rates and the availability of credit     to support our business requirements;
the discovery, estimation, development and replacement of oil, natural gas and NGLs reserves;
our business and financial strategy;
our future operating results;
our drilling locations;
technology;
our cash flow, liquidity and financial position;
the timing and amount of our future production of oil, natural gas and NGLs;
our operating expenses, general and administrative costs, and finding and development costs;
the availability of drilling and production equipment, labor and other services;
our prospect development and property acquisitions;
the marketing of oil, natural gas and NGLs;
competition in the oil, natural gas and NGLs industry;
the impact of weather and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and natural disasters;
governmental regulation of the oil, natural gas and NGLs industry;
environmental regulations;
the effect of legislation, regulatory initiatives and litigation related to climate change;
developments in oil-producing and natural gas-producing countries; and
our strategic plans, objectives, expectations and intentions for future operations.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.






All forward-looking statements, expressed or implied, in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.






GLOSSARY OF TERMS
 
Below is a list of terms that are common to our industry and used throughout this document:
/day
 = per day
 
Mcf
 = thousand cubic feet
 
 
 
 
 
Bbls
 = barrels
 
Mcfe
 = thousand cubic feet of natural gas equivalents
 
 
 
 
 
Bcf
 = billion cubic feet
 
MMBbls
 = million barrels
 
 
 
 
 
Bcfe
 = billion cubic feet equivalents
 
MMBOE
 = million barrels of oil equivalent
 
 
 
 
 
BOE
 = barrel of oil equivalent
 
MMBtu
 = million British thermal units
 
 
 
 
 
Btu
 = British thermal unit
 
MMcf
 = million cubic feet
 
 
 
 
 
MBbls
 = thousand barrels
 
MMcfe
 = million cubic feet equivalent
 
 
 
 
 
MBOE
 = thousand barrels of oil equivalent
 
NGLs
 = natural gas liquids
 
When we refer to oil, natural gas and NGLs in “equivalents,” we are doing so to compare quantities of natural gas with quantities of oil and NGLs or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which 42 gallons is equal to one Bbl of oil or one Bbl of NGLs and one Bbl of oil or one Bbl of NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

References in this report to “us,” “we,” “our,” the “Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC (“VNG”), VNR Holdings, LLC (“VNRH”), Vanguard Permian, LLC (“Vanguard Permian”), Vanguard Operating, LLC (“VO”), VNR Finance Corp. (“VNRF”), Encore Energy Partners Operating LLC (“OLLC”) and Encore Clear Fork Pipeline LLC. References in this report to “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.





PART I
 

ITEM 1.  BUSINESS
 
Overview
 
We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make monthly cash distributions to our unitholders and, over time, increase our monthly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, as of December 31, 2014, we own properties and oil and natural gas reserves primarily located in nine operating basins:

the Green River Basin in Wyoming;

the Piceance Basin in Colorado;

the Permian Basin in West Texas and New Mexico;

the Gulf Coast Basin in Texas, Louisiana and Mississippi;

the Big Horn Basin in Wyoming and Montana;

the Arkoma Basin in Arkansas and Oklahoma;

the Williston Basin in North Dakota and Montana;

the Wind River Basin in Wyoming; and

the Powder River Basin in Wyoming.

We were formed in October 2006 and completed our initial public offering in October 2007. Our common units are listed on the NASDAQ Global Select Market (“NASDAQ”), an exchange of the NASDAQ OMX Group Inc. (Nasdaq: NDAQ), under the symbol “VNR.” Our Series A, Series B and Series C Cumulative Preferred units are also listed on the NASDAQ under the symbols “VNRAP”, “VNRBP” and “VNRCP,” respectively.

1




Organizational Structure

The following diagram depicts our organizational structure as of March 2, 2015:




Recent Developments

Acquisitions of Oil and Natural Gas Properties

Pinedale Acquisition

On January 31, 2014, we completed the acquisition of natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming for approximately $555.6 million in cash with an effective date of October 1, 2013. The purchase price was funded with borrowings under our Reserve-Based Credit Facility (defined in Note 3 of the Notes to the Consolidated Financial Statements included in Part II-Item 8. Financial Statements and Supplementary Data). As of December 31, 2014, based on internal reserve estimates, the interest acquired had estimated total net proved reserves of 705.8 MMcfe, of which 85% was natural gas reserves and 48% was proved developed producing.

Piceance Acquisition

On September 30, 2014, we completed the acquisition of natural gas, oil and NGLs assets in the Piceance Basin in Colorado for approximately $502.1 million in cash. Through this acquisition, we acquired additional interests in the same properties previously acquired in the Rockies Acquisition completed in December 2012. The purchase price was funded with borrowings under our Reserve-Based Credit Facility and is subject to additional customary post-closing adjustments to be determined based on an effective date of July 1, 2014. As of December 31, 2014, based on internal reserve estimates, the interest acquired had estimated total net proved reserves of 336.5 MMcfe, of which 78% was natural gas reserves and 71% was proved developed producing.

2









Other Acquisitions

On May 1, 2014, we completed an asset exchange transaction with Marathon Oil Company in which we acquired natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry Field properties in Wyoming. The total consideration for this transaction was the mutual exchange and assignment of interests in the properties and net cash consideration of $6.8 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our Reserve-Based Credit Facility. This transaction had an effective date of January 1, 2014.

On August 29, 2014, we completed the acquisition of certain natural gas, oil and NGLs properties located in North Louisiana and East Texas for an adjusted purchase price of $269.9 million, subject to additional customary post-closing adjustments to be determined based on an effective date of June 1, 2014.

During the year ended December 31, 2014, we completed other smaller acquisitions of certain natural gas, oil and NGLs properties located in the Permian Basin and Powder River Basin in Wyoming for an aggregate purchase price of $17.7 million.

Equity Offerings

On March 11, 2014, we completed a public offering of 7,000,000 7.625% Series B Cumulative Preferred Units at a price of $25.00 per unit. Offers were made pursuant to a prospectus supplement to our Shelf Registration Statement (discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”). We received proceeds of approximately $169.3 million from this offering, after deducting underwriting discounts of $5.5 million and offering costs of $0.2 million. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.

On September 15, 2014, we completed a public offering of 4,000,000 7.75% Series C Cumulative Preferred Units at a price of $25.00 per unit. Offers were made pursuant to a prospectus supplement to our Shelf Registration Statement. We received proceeds of approximately $96.9 million from this offering, after deducting underwriting discounts of $3.2 million and offering costs of $0.2 million. On September 23, 2014, we received additional proceeds of approximately $7.3 million from the sale of an additional 300,000 Series C Cumulative Preferred Units that were purchased pursuant to the underwriters’ over-allotment option. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.

During the year ended December 31, 2014, total net proceeds received under our at-the-market equity program were approximately $147.8 million, after commissions and fees, from the sales of 4,863,690 common units and $1.2 million, after commissions and fees, from the sales of 45,946 Series A Cumulative Preferred Units.

Proved Reserves

Our total estimated proved reserves at December 31, 2014 were 2,031.3 Bcfe, of which approximately 15% were oil reserves, 73% were natural gas reserves and 12% were NGLs reserves. Of these total estimated proved reserves, approximately 68% were classified as proved developed. At December 31, 2014, estimated future cash inflows from estimated future production of proved reserves were computed using the average oil, natural gas and NGLs price based upon the 12-month average price of $94.87 per barrel of crude oil, $4.36 per MMBtu for natural gas, and $35.35 per barrel of NGLs.

At December 31, 2014, we owned working interests in 9,759 gross (3,664 net) productive wells. Our operated wells accounted for approximately 53% of our total estimated proved reserves at December 31, 2014. Our average net daily production for the year ended December 31, 2014 was 327,109 Mcfe/day. Our average proved reserves-to-production ratio, or average reserve life, is approximately 14 years based on our total proved reserves as of December 31, 2014 and our fourth quarter 2014 annualized production.

Additionally, we own approximately 870,140 gross undeveloped leasehold acres surrounding our existing wells. As of December 31, 2014, we have identified 1,254 proved undeveloped drilling locations and over 3,931 other drilling locations on our leasehold acreage.


3




Business Strategies

Our primary business objective is to generate stable cash flows allowing us to make monthly cash distributions to our unitholders, and over the long-term to increase the amount of our future distributions by executing the following business strategies:
 
Manage our oil and natural gas assets with a focus on maintaining cash flow levels;

Replace reserves and/or production either through the development of our extensive inventory of proved undeveloped locations or make accretive acquisitions of oil and natural gas properties in the known producing basins of the continental United States characterized by a high percentage of producing reserves, long-life, stable production and step-out development opportunities;

Maintain a capital structure which affords financial flexibility for opportunistic acquisitions; and

Use hedging strategies to reduce the volatility in our revenues resulting from changes in oil, natural gas and NGLs prices.

Properties
 
As of December 31, 2014, through certain of our subsidiaries, we own interests in oil and natural gas properties located in nine operating basins. The following table presents the production for the year ended December 31, 2014 and the estimated proved reserves for each operating area: 
 
 
2014 Net Production
 
 
 
 
 
 
Natural Gas
 
Oil
 
NGLs
 
Total
 
Net Estimated
Proved Reserves
 
PV10 Value
 
 
(MMcf)
 
(MBbls)
 
(MBbls)
 
(MMcfe)
 
(MMcfe)
 
(in millions)
Green River Basin
 
30,793

 
306

 
1,216

 
39,921

 
764,877

 
$
828.0

Piceance Basin
 
12,349

 
105

 
519

 
16,094

 
441,673

 
$
515.2

Permian Basin
 
6,363

 
1,046

 
477

 
15,504

 
241,286

 
$
488.5

Gulf Coast Basin
 
2,598

 
358

 
152

 
5,654

 
181,509

 
$
419.6

Big Horn Basin
 
229

 
1,003

 
92

 
6,799

 
104,437

 
$
360.3

Arkoma Basin
 
18,577

 
21

 
235

 
20,113

 
211,503

 
$
203.9

Williston Basin
 
157

 
441

 
6

 
2,843

 
25,097

 
$
89.5

Wind River Basin
 
3,295

 
21

 
62

 
3,791

 
36,842

 
$
48.7

Powder River Basin
 
8,676

 

 

 
8,676

 
24,111

 
$
22.0

 

The following is a description of our properties by operating basin:

Green River Basin Properties

Our Green River Basin properties are comprised of assets in the Pinedale and Jonah Fields of southwestern Wyoming. Production in the Green River Basin is dominated by natural gas and NGLs from tight sands formations. The Pinedale Field lies at depths anywhere between 8,000 to 14,000 feet with similar depths in the adjacent Jonah Field. As of December 31, 2014, our Green River Basin properties consisted of 126,420 gross (35,038 net) leasehold acres. During 2014, the Green River Basin properties produced approximately 39,921 MMcfe of which 77% was natural gas. At December 31, 2014, the properties had total proved reserves of approximately 764,877 MMcfe or 38% of our total estimated proved reserves at year end, of which 52% were proved developed and 84% were natural gas.


4




Piceance Basin Properties

The Piceance Basin is located in northwestern Colorado. Our Piceance Basin properties, which we operate, are located in the Gibson Gulch. The Gibson Gulch area is a basin-centered gas play along the north end of the Divide Creek anticline near the eastern limits of the Piceance Basin’s productive Mesaverde (Williams Fork) trend at depths of approximately 7,500 feet. As of December 31, 2014, our Piceance Basin properties consisted of 24,040 gross (16,075 net) leasehold acres. During 2014, our properties in the Piceance Basin produced approximately 16,094 MMcfe, of which 77% was natural gas. At December 31, 2014, the Piceance Basin properties accounted for approximately 441,673 MMcfe or 22% of our total estimated proved reserves at year end, of which 77% were proved developed and 78% were natural gas.

Permian Basin Properties

The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States extending over West Texas and southeast New Mexico. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. The majority of our producing wells in the Permian Basin are mature oil wells that also produce high-Btu casinghead gas with significant NGLs content. As of December 31, 2014, our Permian Basin properties consisted of 131,797 gross (93,389 net) leasehold acres. During 2014, our Permian Basin operations produced approximately 15,504 MMcfe, of which 59% was oil, condensate and NGLs. At December 31, 2014, these properties accounted for approximately 241,286 MMcfe or 12% of our total estimated proved reserves at year end, of which 77% were proved developed and 51% were oil, condensate and NGLs.

Gulf Coast Basin Properties

Our Gulf Coast Basin properties include properties in the onshore Gulf Coast area, North Louisiana, East Texas, South Texas and Mississippi.

Production from the North Louisiana properties comes from the East Haynesville and Cotton Valley fields. These properties include multiple productive zones including Cotton Valley, James Lime, Pettet, Haynesville, Smackover and Hosston. East Haynesville is located in Claiborne Parish, Louisiana and lies at a depth of about 10,000 to 13,000 feet. The Cotton Valley field is located in Webster Parish, Louisiana and is about 9,000 to 11,000 feet deep. Our production from East Texas properties comes from the Fairway (James Lime Unit) Field in Henderson and Anderson counties.

Most of our South Texas properties are operated by Lewis Petroleum and are located in two fields, Gold River North Field and Sun TSH Field, located in Webb and LaSalle Counties, Texas, respectively. Our working interest ranges from 25% to 100%. Most of the production is high Btu gas that is produced from the Olmos and Escondido sand formations from a depth averaging 7,500 feet.

We operate the majority of our Mississippi properties which are located in the Mississippi Salt Basin. Most of our production comes from the Parker Creek Field in Jones County, Mississippi, where our working interest is approximately 65%. We also have a license for 10 square miles of 3-D seismic data for the development of Parker Creek Field. Our production is mainly oil that produces from the Hosston Formation from a depth ranging from approximately 13,000 feet to 15,000 feet.

Production from our properties in the onshore Gulf Coast Basin comes from the Silsbee Field in Hardin County, Texas.  The Silsbee Field is operated by Silver Oak Energy. Most of the Silsbee production is oil produced from the Yegua formation.

As of December 31, 2014, our Gulf Coast Basin properties consisted of 93,432 gross (45,099 net) leasehold acres. During 2014, the Gulf Coast Basin properties produced approximately 5,654 MMcfe, of which 54% were oil, condensate and NGLs. At December 31, 2014, these properties accounted for approximately 181,509 MMcfe or 9% of our total estimated proved reserves at year end, of which 61% were proved developed and 63% were natural gas.

Big Horn Basin Properties

The Big Horn Basin is a prolific basin which is characterized by oil and natural gas fields with long production histories and multiple producing formations.

Our Elk Basin field is located in Park County, Wyoming and Carbon County, Montana.  We operate all properties in the Elk Basin area which includes the Embar-Tensleep, Madison and Frontier formations as discussed below.


5




Embar-Tensleep Formation.  Production in the Embar-Tensleep formation is being enhanced through a tertiary recovery technique involving effluent gas, or flue gas, from a natural gas processing facility located in the Elk Basin field. From 1949 to 1974, flue gas was injected into the Embar-Tensleep formation to increase pressure and improve production of resident hydrocarbons. Currently, we still use flue gas injection to maintain and improve production within this formation. Our wells in the Embar-Tensleep formation of the Elk Basin field are drilled to a depth of 5,100 to 6,600 feet.
 
Madison Formation.  We plan to concentrate on implementing an injection program to enhance production in the Madison formation. The wells in the Madison formation of the Elk Basin field are drilled to a depth of 4,400 to 7,000 feet.

Frontier Formation.  The Frontier formation is being produced through primary recovery techniques. The wells in the Frontier formation of the Elk Basin field are typically drilled to a depth of 1,400 to 2,700 feet.

We operate and own a 62% interest in the Elk Basin natural gas processing plant near Powell, Wyoming, which was first placed into operation in the 1940s. ExxonMobil Corporation (“Exxon”) owns a 34% interest in the Elk Basin natural gas processing plant, and other parties own the remaining 4% interest. This plant is a refrigeration natural gas processing plant that receives natural gas supplies through a natural gas gathering system from Elk Basin fields.

We also operate and own the Wildhorse pipeline system, which is an approximately 12-mile natural gas gathering system that transports approximately 1.0 MMcf/day of low-sulfur natural gas from the South Elk Basin fields to the Elk Basin natural gas processing plant.

Our Big Horn Basin properties are comprised of assets in Wyoming and the Elk Basin field in south central Montana. We own working interests ranging from 4% to 100% in our Big Horn Basin properties, which consisted of 24,512 gross (15,632 net) leasehold acres as of December 31, 2014. During 2014, our properties in the Big Horn Basin produced approximately 6,799 MMcfe, of which 88% was oil. At December 31, 2014, the Big Horn Basin properties accounted for approximately 104,437 MMcfe or 5% of our total estimated proved reserves at year end, of which 95% were proved developed and 95% were oil, condensate and NGLs.

Arkoma Basin Properties

Our Arkoma Basin properties include properties in the Woodford Shale, located in eastern Oklahoma, the Fayetteville Shale, located in Arkansas, and royalty interests and non-operated working interest in both states. As of December 31, 2014, our Arkoma Basin properties consisted of 148,467 gross (73,140 net) leasehold acres. During 2014, the Arkoma Basin properties produced approximately 20,113 MMcfe, of which 92% was natural gas. At December 31, 2014, the properties had total proved reserves of approximately 211,503 MMcfe or 10% of our total estimated proved reserves at year end, of which 80% were proved developed and 91% were natural gas.

Williston Basin Properties

Our Williston Basin properties are located in North Dakota and Montana, which include, among others, the Horse Creek Field, the Charlson Madison Unit and the Elk field. The Horse Creek field is located in Bowman County, North Dakota and has producing oil wells from multiple horizons in the Red River formation. The Charlson Madison Unit produces from the unitized Madison formation. The Elk field is operated and produces from wells in McKenzie County, North Dakota. As of December 31, 2014, our Williston Basin properties consisted of 550,996 gross (71,960 net) leasehold acres. During 2014, the properties produced approximately 2,843 MMcfe, of which 93% was oil. Our Williston Basin properties had estimated proved reserves at December 31, 2014 of 25,097 MMcfe or 1% of our total estimated proved reserves at year end, of which 96% were proved developed and 94% were oil.

Wind River Basin Properties

The Wind River Basin is located in central Wyoming. Our activities are concentrated primarily in the eastern Wind River Basin, along the greater Waltman Arch. Our natural gas production in this basin is gathered through our own gathering systems and delivered to markets through pipelines owned by Kinder Morgan Interstate and Colorado Interstate Gas (“CIG”). As of December 31, 2014, our Wind River Basin properties consisted of 231,685 gross (197,369 net) leasehold acres. During 2014, our Wind River Basin properties produced approximately 3,791 MMcfe, of which 87% was natural gas. At December 31, 2014, the properties had total proved reserves of approximately 36,842 MMcfe or 2% of our total estimated proved reserves, of which 95% were proved developed and 82% were natural gas.

Powder River Basin Properties

6





The Powder River Basin is primarily located in northeastern Wyoming. Our development operations are conducted in our coalbed methane (“CBM”) fields. CBM wells are drilled to 1,500 feet on average, targeting the Big George Coals, typically producing water in a process called dewatering. This process lowers reservoir pressure, allowing the gas to desorb from the coal and flow to the well bore. As the reservoir pressure declines, the wells begin producing methane gas at an increasing rate. As the wells mature, the production peaks, stabilizes and then begins declining. The average life of a CBM well can range from five to eleven years depending on the coal seam. Our natural gas production in this basin is gathered through gathering and pipeline systems owned by Fort Union Gas Gathering, LLC and Thunder Creek Gas Services. As of December 31, 2014, our Powder River Basin properties consisted of 114,287 gross (66,866 net) leasehold acres. During 2014, the properties produced approximately 8,676 MMcfe, which was 100% natural gas. At December 31, 2014, the properties had total proved reserves of approximately 24,111 MMcfe or 1% of our total estimated proved reserves at year end, of which 77% were proved developed.

Oil, Natural Gas and NGLs Prices

We analyze the prices we realize from sales of our oil and natural gas production and the impact on those prices of differences in market-based index prices and the effects of our derivative activities. We market our oil and natural gas production to a variety of purchasers based on regional pricing. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. The West Texas Intermediate Cushing, or “WTI” price of crude oil is a widely used benchmark in the pricing of domestic and imported oil in the United States. The relative value of crude oil is mainly determined by its quality and location. In the case of WTI pricing, the crude oil is light and sweet, meaning that it has a higher specific gravity (lightness) measured in degrees of API (“American Petroleum Institute”) gravity and low sulfur content, and is priced for delivery at Cushing, Oklahoma. In general, higher quality crude oils (lighter and sweeter) with fewer transportation requirements result in higher realized pricing for producers.

Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted.  Since title of the natural gas sold under these contracts passes at the outlet of the processing plant, we report residue volumes of natural gas in Mcf as production. As a result of the incremental NGLs value and the improved differential, the price we were paid per Mcf, before deductions for gathering, transportation and processing fees, for natural gas sold under certain contracts during 2014 increased to a level above NYMEX.

The average realized prices described below include deductions for gathering, transportation and processing fees, however, these prices do not include the impact of our hedges.

Production in the Green River Basin is predominantly natural gas and is processed for the recovery of NGLs. The processed natural gas is subject to a processing agreement with Western Gas Resources in their Granger Plant facility where we take our residue natural gas in-kind for sales and NGLs are sold pursuant to the terms of the processing agreement. We market our Green River Basin residue natural gas into the Rockies market through the use of multiple pipeline connections. During 2014, we received the average NYMEX price less $0.52 per Mcf in the Green River Basin. Due to the decrease in the ethane price during 2014, the Granger Plant made an economic decision to reject ethane effective January 2015.

Production in the Piceance Basin is predominantly natural gas and is processed for the recovery of NGLs. The processed gas is subject to a processing agreement with Enterprise Gas Processing LLC, in their Meeker Plant facility. We market our natural gas production into the Rockies market at the Northwest Rockies index pricing. During 2014, we received the average NYMEX price less $1.11 per Mcf in the Piceance Basin.

In the Permian Basin, most of our natural gas production is casinghead natural gas produced in conjunction with our oil production.  Casinghead gas typically has a high Btu content and requires processing prior to sale to third parties. We have a number of processing agreements in place with gatherers/processors of our casinghead natural gas, and we share in the revenues associated with the sale of NGLs resulting from such processing, depending on the terms of the various agreements. For the year ended December 31, 2014, we received the average NYMEX price less $0.31 per Mcf in the Permian Basin. Our oil production is sold under month-to-month sales contracts with purchasers that take delivery of the oil volumes at the tank batteries adjacent to the producing wells. We sell oil production from our operated Permian Basin properties at the wellhead to third party gathering and marketing companies. During 2014, we received the average WTI price less $8.57 per barrel in the Permian Basin.

In the Gulf Coast Basin, our natural gas production has a high Btu content and requires processing prior to sale to third parties. Our proportionate share of the natural gas volumes are sold at the tailgate of the processing plant at the Houston Ship

7




Channel and Waha Gas Index pricing which typically results in a discount to NYMEX prices. For the year ended December 31, 2014, we received the average NYMEX price less $0.14 per Mcf.

The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections with other pipelines.  Our Big Horn Basin sweet crude oil production is transported from the field by a third-party trucking company that delivers the crude oil to a centralized facility connected to a common carrier pipeline with delivery points accessible to local refiners in the Salt Lake City, Utah and Guernsey, Wyoming market centers. During 2014, we received the average NYMEX price less $12.54 per barrel in the Big Horn Basin. Effective March 2015, we entered into a sales contract under Western Canadian Select (“WCS”) index pricing, which provides the opportunity for us to enter into hedges for our Elk Basin production and therefore reduce our exposure to price volatility.

Our Arkoma Basin production in the southeastern Oklahoma Woodford Shale consists predominately of natural gas with a mix of high Btu processed natural gas and unprocessed lean natural gas. The natural gas production is gathered by multiple third party entities with the processed natural gas ultimately delivered to the Atlas Resources natural gas processing complex. The processed natural gas is subject to a processing agreement with Atlas Resources, where we take our residue natural gas in-kind for sales, and NGLs are sold pursuant to the terms of the processing agreement. The lean natural gas is primarily delivered directly to market. The natural gas is marketed into the Enable Gas: East index and Transcontinental Gas Pipeline Corp: Zone 4 index via a firm transportation contract that was in place prior to our acquisition of these natural gas properties. For the year ended December 31, 2014, we received the average NYMEX price less $1.42 per Mcf.
 
Our Wind River Basin properties are predominantly natural gas plays with approximately two-thirds of the production being processed at natural gas plants for the extraction of NGLs. Our residue natural gas is sold into the Rockies market at the CIG price while the NGLs are sold to a third-party natural gas processor pursuant to a processing agreement. The Powder River natural gas production is classified as Coal Bed Methane (“CBM”) gas and, as it is a very dry gas, is sold directly into the market upon being handled with conventional separation, treating, and transportation. The CBM gas is sold into the Rockies market at the CIG index price as well. During 2014, we received the average NYMEX price less $0.29 per Mcf in the Wind River Basin while we received the average NYMEX price less $2.16 per Mcf in the Powder River Basin.

In the Williston Basin, we produce a combination of sweet and legacy sour oil. This oil is both connected to oil pipelines as well as trucked out for sales and there is minimal natural gas associated with this production. During 2014, we received the average NYMEX price less $13.51 per barrel in the Williston Basin.

Oil, Natural Gas and NGLs Data

Estimated Proved Reserves
 
The following table presents our estimated net proved oil, natural gas and NGLs reserves and the present value of the estimated proved reserves at December 31, 2014, as estimated by our internal reserve engineers. The estimate of net proved reserves has not been filed with or included in reports to any federal authority or agency. The Standardized Measure value shown in the table is not intended to represent the current market value of our estimated oil, natural gas and NGLs reserves. Please see “Reserves Estimation Process” below and the “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report for additional information regarding our estimated proved reserves.
 

8




Reserve Data:
 
Estimated net proved reserves:
 
Crude oil (MMBbls)
50.0

Natural gas (Bcf)
1,475.9

NGLs (MMBbls)
42.5

Total (Bcfe)
2,031.3

Proved developed (Bcfe)
1,377.6

Proved undeveloped (Bcfe)
653.7

Proved developed reserves as % of total proved reserves
68
%
Standardized Measure (in millions) (1)(2)
$
2,975.7

Representative Oil and Natural Gas Prices (3):


Oil—WTI per Bbl
$
94.87

Natural gas—Henry Hub per MMBtu
$
4.36

NGLs—Volume-weighted average price per Bbl
$
35.35


(1)
Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) (using the 12-month unweighted average of first-day-of-the-month price, the “12-month average price”) without giving effect to non-property related expenses such as selling, general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion, amortization and accretion and discounted using an annual discount rate of 10%. Our Standardized Measure does not include future income tax expenses because we are not subject to income taxes and our reserves are owned by our subsidiaries which are also not subject to income taxes. Standardized Measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Item 1. Business—Operations—Price Risk and Interest Rate Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

(2)
For an explanation of Standardized Measure, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

(3)
Oil and natural gas prices are based on spot prices per Bbl and MMBtu, respectively, calculated using the “12-month average price” for January through December 2014, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price. NGLs prices were calculated using the differentials to the WTI price per Bbl of $94.87.
 

9




The following tables set forth certain information with respect to our estimated proved reserves by operating basin as of December 31, 2014:
 
 
Estimated Proved Developed
Reserve Quantities
 
Estimated Proved Undeveloped
Reserve Quantities
 
Estimated Proved
Reserve Quantities
 
 
Natural Gas
(Bcf)
 
Oil
(MMBbls)
 
NGLs
(MMBbls)
 
Total
(Bcfe)
 
Natural Gas
(Bcf)
 
Oil
(MMBbls)
 
NGLs
(MMBbls)
 
Total
(Bcfe)
 
Total
(Bcfe)
Operating Basin
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Green River Basin
 
335.2

 
3.1

 
6.8

 
394.5

 
310.1

 
2.9

 
7.2

 
370.4

 
764.9

Piceance Basin
 
268.1

 
2.0

 
10.0

 
339.9

 
78.7

 
0.8

 
3.1

 
101.8

 
441.7

Permian Basin
 
88.7

 
10.7

 
5.3

 
185.0

 
28.9

 
2.9

 
1.7

 
56.3

 
241.3

Gulf Coast Basin
 
65.3

 
5.5

 
2.1

 
111.3

 
48.3

 
3.2

 
0.4

 
70.2

 
181.5

Big Horn Basin
 
4.6

 
13.8

 
2.0

 
99.4

 

 
0.8

 

 
5.0

 
104.4

Arkoma Basin
 
159.1

 

 
1.8

 
169.8

 
33.2

 

 
1.4

 
41.7

 
211.5

Williston Basin
 
1.3

 
3.8

 

 
24.1

 
0.1

 
0.1

 

 
1.0

 
25.1

Wind River Basin
 
29.8

 
0.2

 
0.7

 
35.0

 
0.3

 
0.2

 

 
1.8

 
36.8

Powder River Basin
 
18.6

 

 

 
18.6

 
5.6

 

 

 
5.5

 
24.1

Total
 
970.7

 
39.1

 
28.7

 
1,377.6

 
505.2

 
10.9

 
13.8

 
653.7

 
2,031.3


 

PV10 Value (1)


Developed

Undeveloped

Total
Operating Basin

(in millions)
Green River Basin
 
$
580.5

 
$
247.5

 
$
828.0

Piceance Basin

460.3

 
54.9

 
515.2

Permian Basin

426.1

 
62.4

 
488.5

Gulf Coast Basin

284.5

 
135.1

 
419.6

Big Horn Basin
 
343.2

 
17.1

 
360.3

Arkoma Basin

191.4

 
12.5

 
203.9

Williston Basin

87.9

 
1.6

 
89.5

Wind River Basin
 
44.7

 
4.0

 
48.7

Powder River Basin

19.9

 
2.1

 
22.0

Total

$
2,438.5

 
$
537.2

 
$
2,975.7

 
 
(1)
PV10 is not a measure of financial or operating performance under generally accepted accounting principles, or “GAAP,” nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. However, for Vanguard, PV10 is equal to the standardized measure of discounted future net cash flows under GAAP because the Company is not a tax paying entity. For our presentation of the standardized measure of discounted future net cash flows, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

The data in the above tables represent estimates only. Oil, natural gas and NGLs reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future sales prices may differ from those assumed in these estimates. Please read “Item 1A. Risk Factors.”
 
In accordance with the guidelines of the SEC, our internal reserve engineers’ estimates of future net revenues from our properties, and the standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the unweighted arithmetic average first day of the month prices for the 12-month period ended December 31, 2014 for each product.

10





Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to the timing of future production, which may prove to be inaccurate.
 
From time to time, we engage reserve engineers to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither the reserve engineers nor any of their respective employees have any interest in those properties and the compensation for these engagements is not contingent on their estimates of reserves and future net revenues for the subject properties. During 2014, we paid DeGolyer and MacNaughton (“D&M”) approximately $0.1 million for all reserve and economic evaluations.

Proved Undeveloped Reserves

Our proved undeveloped reserves at December 31, 2014, as estimated by our internal reserve engineers, were 653.7 Bcfe, consisting of 10.9 MMBbls of oil, 505.2 Bcf of natural gas and 13.8 MMBbls of NGLs. Our proved undeveloped reserves increased by 429.7 Bcfe during the year ended December 31, 2014, as compared to our proved undeveloped reserves as of December 31, 2013. The increase in proved undeveloped reserves during 2014 resulted from the addition of 517.4 Bcfe from the acquisitions of natural gas and oil properties completed during 2014 and a net increase of 34.6 Bcfe in revisions of previous quantities estimates and changes in prices. The increase is offset by a decrease of 101.2 Bcfe due to revisions in the timing of our drilling development plan primarily in the Arkoma Basin. Additionally, we developed approximately 21.1 Bcfe of our total proved undeveloped reserves booked as of December 31, 2013 through the drilling of 53 gross (6.08 net) wells.

We expect to spend approximately 57% of our planned five year future development costs within the next three years as reflected in our reserve report. During the year ended December 31, 2014, we spent $16.6 million or approximately 15% of our 2014 capital budget converting proved undeveloped reserves recorded at December 31, 2013 to proved developed reserves. Our development plan for drilling proved undeveloped wells includes the drilling of 371 net wells before the end of 2019 at an estimated cost of $806.3 million. This development plan calls for the drilling of 44 net wells during 2015, 80 net wells during 2016, 91 net wells during 2017, 83 net wells during 2018 and 73 net wells during 2019. Additionally, the expected plan of development of our natural gas proved undeveloped reserves, which represent 77% of our total proved undeveloped reserves at December 31, 2014, over the next five years is as follows:
 
Percent of Natural Gas
Proved Undeveloped Reserves
Expected to be Converted
2015
16%
2016
19%
2017
22%
2018
22%
2019
21%
Total
100%

At December 31, 2014, none of our proved undeveloped properties are scheduled to be drilled on a date more than five years from the date the reserves were initially booked as proved undeveloped. Additionally, none of our proved undeveloped reserves at December 31, 2014 have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves.

Substantially all of our developed and undeveloped leasehold acreage is held by production, which means that as long as our wells on the acreage continue to produce, we will continue to hold the leases. The leases in which we hold an interest that are not held by production are not material to us.

Reserve Estimation Process

Estimates of proved reserves at December 31, 2014 were based on studies performed by our internal reservoir engineers in accordance with guidelines established by the SEC. Our reserve estimation process is a collaborative effort coordinated by our reservoir engineers in compliance with our internal controls for such process. Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, including crude

11




oil, natural gas and NGLs prices, production costs, future capital expenditures and our net ownership percentages are obtained from other departments within the Company. Our internal reservoir engineers perform review procedures with respect to such non-technical inputs. Reserve variances are discussed among the internal reservoir engineers and the Executive Vice President of Operations.

Our reserve engineering group is directly responsible for our reserve evaluation process and consists of four professionals, two of whom hold, at a minimum, bachelor’s degrees in engineering. Within our Company, Michael Egerman, Reserves and Budget Manager, is the technical person primarily responsible for overseeing the preparation of the reserve estimates. Mr. Egerman has over 10 years of experience and graduated from the University of Texas at Austin with a Bachelor of Science degree in Petroleum Engineering in 2004. He is a member of the Society of Petroleum Engineers.

The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Independent Audit of Reserves

We engage independent petroleum engineers to audit a substantial portion of our reserve estimates. Our audit procedures require the independent engineers to prepare their own estimates of proved reserves for properties comprising at least 80% of our year-end proved reserves. Our Board of Directors requires that the independent petroleum engineers’ estimate of reserve quantities for the properties audited by the independent petroleum engineers are within 10% of our internal estimate.  Once completed, our year-end reserves are presented to senior management, including the President and Chief Executive Officer, the Executive Vice President and Chief Financial Officer, and the Executive Vice President of Operations, for approval.

For the year ended December 31, 2014, we engaged D&M, an independent petroleum engineering firm, to perform reserve audit services. The opinion by D&M for the year ended December 31, 2014 covered producing areas containing 80.7% of our proved reserves on a net-equivalent-barrel-of-oil basis. D&M’s opinion indicates that the estimates of proved reserves prepared by our internal reserves engineers for the properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially from the estimates prepared by D&M. Such estimates by D&M in the aggregate were within our 10% variation tolerance when compared to those prepared by our reserves engineering group. The report prepared by D&M was developed utilizing geological and engineering data we provided. The report of D&M dated February 19, 2015, which contains further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M’s technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report on Form 10-K and incorporated herein by reference.

Within D&M, the lead technical person primarily responsible for overseeing the audit of our reserves is Mr. Gregory K. Graves. Mr. Graves is a Senior Vice President with D&M and has over 30 years of experience in oil and gas reservoir studies and reserves evaluations. He graduated from the University of Texas at Austin in 1984 with a Bachelor of Science Degree in Petroleum Engineering and is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists. Mr. Graves meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain price and cost information for each of the periods indicated. Information for fields with greater than 15% of our total proved reserves have been listed separately in the table below for the year ended December 31, 2014. None of our fields had proved reserves that were greater than 15% of our total proved reserves during 2013 and 2012.

12




 
 
Net Production(1)
 
Average Realized Sales Prices (2)
 
Production Cost (3)
 
 
Crude Oil
Bbls/day
 
Natural Gas
Mcf/day
 
NGLs
Bbls/day
 
Crude Oil
Per Bbl
 
Natural Gas
Per Mcf
 
NGLs
Per Bbl
 
Per Mcfe
Year Ended December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale (Green River Basin)
 
659

 
72,090

 
3,028

 
$
77.76

 
$
3.96

 
$
13.76

 
$
0.43

Mamm Creek (Piceance Basin)
 
288

 
32,455

 
1,424

 
$
72.85

 
$
3.33

 
$
25.71

 
$
0.71

All other fields
 
8,096

 
122,953

 
3,107

 
$
83.66

 
$
3.27

 
$
37.14

 
$
1.54

Total
 
9,043

 
227,498

 
7,559

 
$
82.88

 
$
3.50

 
$
25.62

 
$
1.11

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 

 
 

 
 
 
 
 
 
 
 
All fields
 
8,462

 
137,632

 
4,047

 
$
82.26

 
$
3.39

 
$
33.76

 
$
1.36

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
All other fields
 
7,536

53,695

53,695

84

1,813

45.11

$
84.00

 
$
4.47

 
$
45.11

 
$
1.85


(1)
Average daily production for 2014 and 2013 calculated based on 365 days and for 2012 calculated based on 366 days including production for all of our acquisitions from the closing dates of these acquisitions.

(2)
Average realized sales prices include the impact of hedges but exclude the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. The average realized prices also reflect deductions for gathering, transportation and processing fees. For details on average sales prices without giving effect to the impact of hedges please see “Item 7. Management Discussion and Analysis of Financial Condition-Year Ended December 31, 2014 compared to Year Ended December 31, 2013” and “Item 7. Management Discussion and Analysis of Financial Condition -Year Ended December 31, 2013 compared to Year Ended December 31, 2012.”

(3)
Production costs include such items as lease operating expenses and exclude production taxes (severance and ad valorem taxes).

Productive Wells

The following table sets forth information at December 31, 2014 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
 
 
 
Natural Gas Wells
 
Oil Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Green River Basin
 
2,438

 
389

 
22

 
20

 
2,460

 
409

Piceance Basin
 
1,056

 
918

 

 

 
1,056

 
918

Permian Basin
 
554

 
264

 
2,536

 
691

 
3,090

 
955

Gulf Coast Basin
 
592

 
304

 
126

 
65

 
718

 
369

Big Horn Basin
 
5

 
3

 
299

 
215

 
304

 
218

Arkoma Basin
 
1,119

 
181

 
14

 
2

 
1,133

 
183

Williston Basin
 
30

 
9

 
137

 
76

 
167

 
85

Wind River Basin
 
135

 
128

 
9

 
8

 
144

 
136

Powder River Basin
 
687

 
391

 

 

 
687

 
391

Total
 
6,616

 
2,587

 
3,143

 
1,077

 
9,759

 
3,664


Developed and Undeveloped Leasehold Acreage

13





The following table sets forth information as of December 31, 2014 relating to our leasehold acreage.
 
 
 
Developed Acreage (1)
 
Undeveloped Acreage (2)
 
Total Acreage
 
 
Gross (3)
 
Net (4)
 
Gross (3)
 
Net (4)
 
Gross (3)
 
Net (4)
Green River Basin
 
60,730

 
24,705

 
65,690

 
10,333

 
126,420

 
35,038

Piceance Basin
 
16,112

 
10,477

 
7,928

 
5,598

 
24,040

 
16,075

Permian Basin
 
115,254

 
83,536

 
16,543

 
9,853

 
131,797

 
93,389

Gulf Coast Basin
 
73,942

 
33,159

 
19,490

 
11,940

 
93,432

 
45,099

Big Horn Basin
 
23,392

 
14,559

 
1,120

 
1,073

 
24,512

 
15,632

Arkoma Basin
 
132,701

 
64,686

 
15,766

 
8,454

 
148,467

 
73,140

Williston Basin
 
65,270

 
35,280

 
485,726

 
36,680

 
550,996

 
71,960

Wind River Basin
 
22,989

 
21,026

 
208,696

 
176,343

 
231,685

 
197,369

Powder River Basin
 
65,106

 
37,868

 
49,181

 
28,998

 
114,287

 
66,866

Total
 
575,496

 
325,296

 
870,140

 
289,272

 
1,445,636

 
614,568

 
(1)
Developed acres are acres spaced or assigned to productive wells.

(2)
Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such leasehold acreage contains proved reserves.

(3)
A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)
A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Drilling Activity

The following is a description of the Company’s drilling and completion activities during the year ended December 31, 2014.

In the Green River Basin, we participated in the drilling of 122 wells with an average working interest of 13%. We also participated in the completion of 136 wells with an average working interest of 12%. These wells are in Sublette County, in southwestern Wyoming and are directionally drilled from pads but are vertical through the 4,000 feet pay section. The average well depth is approximately 14,000 feet or a true vertical depth of 12,000 feet and are typically completed with an average of 16 frac stages.

We participated in the drilling of two coal bed methane wells in our Piceance Basin with a 21.5% working interest in each well.  These wells were horizontal (dual lateral) wells drilled to the Fruitland Coal in La Plata County, Colorado. Total drilled depth is approximately 6,500 feet with true vertical depth of approximately 2,400 feet.

In the Permian Basin, we participated in drilling five vertical and three horizontal wells in the Midland, Dawson, Gaines and Ward Counties in Texas. Our working interests in these wells range between approximately 2% to 35%. We also completed a well in the Ector County where we have a 100% working interest. Most of these wells were drilled to a vertical depth of approximately 7,300 feet and were completed in the Clearfork, Tubb, Glorietta or Wolfcamp formations. As a method to balance our capital investments, we promoted some of our working interest in a number of our Permian proved undeveloped locations including the horizontal Bone Springs wells in Ward County, Texas and are attempting to do the same with some vertical Wolfberry wells in Martin County, Texas.

In the Gulf Coast Basin, we participated in the drilling of three vertical wells in the Jones County in Mississippi with an average working interest of 22%. These wells were drilled to an average depth 19,000 feet. In addition, we participated in the completion of four wells with an average working interest of 22%.


14




In the Arkoma Basin, we participated in drilling 10 gross (0.2 net) horizontal wells in Hughes and Coal Counties in Woodford, Oklahoma and in completing 27 gross (3.5 net) horizontal wells in several counties also in Woodford, Oklahoma. We also participated in drilling 16 gross (0.5 net) and completing 33 gross (1.7 net) horizontal wells in Fayetteville, Oklahoma during the year in the White, Cleburne, Van Buren and Conway Counties.

In the Williston Basin, we participated in drilling three horizontal oil wells in the Williams and Billings counties in North Dakota with working interests ranging from 4% to 25% during 2014. These wells are in the Bakken shale and Three Forks formation and were drilled to an average total depth of about 22,500 feet or a true vertical depth of approximately 11,000 feet.

In the Powder River Basin, we drilled four vertical wells during 2014 in the Johnson field in Wyoming with an average working interest of 67%. These wells were drilled to a vertical depth of approximately 1,350 feet. We also participated in completing a well in the same field with a 16% working interest.

During 2015, we intend to concentrate our drilling on low risk, development opportunities with the majority of drilling capital focused on high Btu natural gas wells. We currently anticipate a capital budget for 2015 of approximately $113.5 million, excluding any potential future acquisitions. We expect to spend 50% of the 2015 capital budget in the Green River Basin where we will participate as a non-operated partner in the drilling and completion of vertical natural gas wells. Additionally, we expect to spend 25% of the 2015 capital budget in the Gulf Coast Basin on the newly acquired East Haynesville assets, drilling both vertical and horizontal wells and several recompletion projects. The balance of the 2015 budget is related to maintenance activities in our other operating areas.   

The following table sets forth information with respect to wells completed during the years ended December 31, 2014, 2013 and 2012. Our drilling activity during these periods has consisted entirely of drilling development wells. We have not drilled any exploratory wells during these periods. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of oil, natural gas, and NGLs regardless of whether they produce a reasonable rate of return.
 

Year Ended December 31,
 

2014

2013

2012
Gross wells:

 


 


 

Productive

215


78


27

Dry






Total

215


78


27

Net Development wells:

 

 


 

Productive

27.2


6.9


6.6

Dry






Total

27.2


6.9


6.6


Operations
 
Principal Customers

For the year ended December 31, 2014, sales of oil, natural gas and NGLs to Anadarko Petroleum Corporation, Marathon Oil Company, Cardinal Midstream LLC, Plains Marketing, LP and Bill Barrett Corporation accounted for approximately 19%, 12%, 9%, 7% and 5%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2014 therefore accounted for 52% of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash available for distribution could decline. However, if we were to lose a customer, we believe a substitute purchaser could be identified in a timely manner and upon similar terms and conditions.


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Delivery Commitments and Marketing Arrangements

Our oil and natural gas production is principally sold to marketers, processors, refiners, and other purchasers that have access to nearby pipeline, processing and gathering facilities. In areas where there is no practical access to pipelines, oil is trucked to central storage facilities where it is aggregated and sold to various markets and downstream purchasers. Our production sales agreements generally contain customary terms and conditions for the oil and natural gas industry, provide for sales based on prevailing market prices in the area, and generally are month-to-month or have terms of one year or less.

We generally sell our natural gas production from our operated properties on the spot market or under market-sensitive, short-term agreements with credit-worthy purchasers, including independent marketing companies, gas processing companies, and other purchasers who have the ability to pay the highest price for the natural gas production and move the natural gas under the most efficient and effective transportation agreements. Because all of our natural gas production from our operated properties is sold under market-priced agreements, we are positioned to take advantage of future increases in natural gas prices but we are also subject to any future price declines. We do market our own natural gas on some of our non-operated properties.

The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections to other export pipelines. Our Big Horn Basin sweet crude oil production is transported from the field by a third party trucking company that delivers the crude oil to a centralized facility connected to a common carrier pipeline with delivery points accessible to local refiners in the Salt Lake City, Utah and Guernsey, Wyoming market centers. We sell oil production from our operated Permian Basin properties at the wellhead to third-party gathering and marketing companies.

Our natural gas is transported through our own and third-party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party gatherer, processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we may enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. Currently, a majority of our existing firm transportation agreements were assumed in connection with acquisitions of oil and natural gas properties. These agreements have term delivery commitments of fixed and determinable quantities of natural gas. Please see “Item 7. Management’s Discussion and Analysis and Results of Operations—Commitments and Contractual Obligations” for additional information regarding our long-term firm transportation contracts.

The following table sets forth information about material long-term firm transportation contracts for pipeline capacity, which typically require a demand charge. We source the gas to meet these commitments from our producing properties. We have certain commitments that we assumed as part of our acquisitions of oil and gas properties where the production from the acquired properties and the production of joint interest owners that we market were not adequate to meet the commitments resulting to us paying the set demand charge relating to the maximum daily quantity outlined in the contract.
Type of Arrangement
 
Pipeline System /Location
 
Deliverable Market
 
Gross Deliveries (MMBtu/d)
 
Term
Firm Transport
 
WIC Medicine Bow
 
Rocky Mountains
 
30,000
 
01/15 – 03/15
Firm Transport
 
WIC Medicine Bow
 
Rocky Mountains
 
25,000
 
01/15 – 06/20
Firm Transport
 
Questar Pipeline
 
Rocky Mountains
 
12,000
 
01/15 – 10/15
Firm Transport
 
Colorado Interstate Gas
 
Rocky Mountains
 
8,700
 
01/15 – 9/16
Firm Transport
 
Cheyenne Plains
 
Midcontinent
 
9,000
 
01/15 – 05/17
Firm Transport
 
Cheyenne Plains
 
Midcontinent
 
5,000
 
06/17 – 05/18
Firm Transport
 
Rockies Express
 
Northeast
 
25,000
 
01/15 – 11/19
Firm Transport
 
Gulf Crossing Pipeline
 
Mississippi-Alabama
 
10,000
 
01/15 – 07/15
Firm Transport
 
Gulf Crossing Pipeline
 
Mississippi-Alabama
 
10,000
 
01/15 – 07/16

Price Risk and Interest Rate Management Activities

We routinely enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil, natural gas and NGLs price volatility on our cash flow from operations. Currently, we primarily use fixed-price swaps, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices. By removing the price volatility from a significant portion

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of our oil and natural gas production, we have mitigated for a period of time, but not eliminated, the potential effects of fluctuation in oil and natural gas prices on our cash flow from operations. For a description of our derivative positions, please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Competition
 
The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staff substantially larger than ours or a different business model. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial, technical or personnel resources will permit.
 
We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development program.
 
Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure unitholders that we will be able to compete satisfactorily when attempting to make further acquisitions.
 
Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, however, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our oil and natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests, contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for taxes not yet payable and other burdens, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with our use of these properties in the operation of our business.

Natural Gas Gathering

We own and operate a network of natural gas gathering systems in the Big Horn Basin, Piceance Basin and Gulf Coast Basin in East Texas. These systems gather and transport our natural gas and a small amount of third-party natural gas to larger gathering systems and intrastate, interstate and local distribution pipelines. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to:

realize faster connection of newly drilled wells to the existing system;
control pipeline operating pressures and capacity to maximize production;
control compression costs and fuel use;
maintain system integrity;
control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and
track sales volumes and receipts closely to assure all production values are realized.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in some of our operating areas, and as a result we generally perform the majority of our drilling in these areas during the summer and fall months. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase

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competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increased costs or delay our operations. Generally, but not always, oil is typically in higher demand in the summer for its use in road construction and natural gas is in higher demand in the winter for heating. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.
 
Environmental and Occupational Health and Safety Matters

General.   Our business involving the acquisition and development of oil and natural gas properties is subject to extensive and stringent federal, state and local laws and regulations governing the discharge of materials into the environment, environmental protection, and the health and safety of employees. These operations are subject to the same environmental, health and safety laws and regulations as other similarly situated companies in the oil and natural gas industry. These laws and regulations may:
 
require the acquisition of permits before commencing drilling or other regulated activities;

require the installation of expensive pollution control equipment and performance of costly remedial measures to mitigate or prevent pollution from historical and ongoing operations, such as pit closure and plugging of abandoned wells;

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

impose specific health and safety criteria addressing worker protection;

impose substantial liabilities for pollution resulting from operations; and

require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement for operations affecting federal lands or leases.

Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, imposition of removal or remedial obligations, and the issuance of orders enjoining some or all of our operations deemed in non-compliance. Moreover, these laws and regulations may restrict our ability to produce oil, natural gas and NGLs by, among other things, limiting production from our wells, limiting the number of wells we are allowed to drill or limiting the locations at which we may conduct our drilling operations. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly well drilling, construction, completion and water management activities, or waste handling, disposal and clean-up requirements for the oil and natural gas industry could have a significant impact on our operating costs. We believe that operation of our wells is in substantial compliance with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot provide any assurance on how future compliance with existing or newly adopted environmental laws and regulations may impact our properties or the operations. For the year ended December 31, 2014, we did not incur any material capital expenditures for performance of remediation or installation of pollution control equipment at any of our facilities; however, we did incur capital expenditures in the ordinary course of business to comply with pollution control requirements. As of the date of this Annual Report, we are not aware of any environmental issues or claims that will require material capital expenditures during 2015 or that will otherwise have a material adverse impact on our financial position or results of operations.
 
The following is a summary of the more significant existing environmental and occupational health and safety laws to which our business operations are subject and for which compliance may have a material adverse impact on our operations as well as the oil and natural gas exploration and production industry in general.
 
Waste Handling.  The Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state laws, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” as well as the disposal of non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or “EPA,” individual states administer some or all of the federal provisions of RCRA, sometimes in conjunction with their own, more stringent state requirements. Drilling fluids, produced waters, and many other wastes associated with the exploitation, development, and production of crude oil, natural gas, or geothermal energy are currently regulated under RCRA’s less stringent non-hazardous waste provisions. However, by

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amendment of existing RCRA laws and regulations, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could increase our costs to manage and dispose of such generated wastes, which cost increase could be significant. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as RCRA hazardous wastes.
 
 Hazardous Substance Releases.   The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA,” or “Superfund,” and analogous state laws, impose joint and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that transported or disposed or arranged for the transportation or disposal of the hazardous substance found at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While materials are generated in the course of operation of our wells that may be regulated as hazardous substances, we have not received any pending notifications that we may be potentially responsible for cleanup costs under CERCLA.
 
We currently own, lease, or have a non-operating interest in numerous properties that have been used for oil and natural gas production for many years. Although we believe that operating and waste disposal practices used on these properties in the past were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where these substances, wastes and hydrocarbons have been taken for treatment or disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Our Elk Basin assets include a natural gas processing plant. Previous environmental investigations of the Elk Basin natural gas processing plant indicate historical soil and groundwater contamination by hydrocarbons and the presence of asbestos-containing material at the site. Although the environmental investigations did not identify an immediate need for remediation of the suspected historical hydrocarbon contamination or abatement of the asbestos, the extent of the hydrocarbon contamination is not known and, therefore, the potential liability for remediating this contamination may be significant. In the event we cease operating the gas plant, the cost of decommissioning it and addressing the previously identified environmental conditions and other conditions, such as waste disposal, could be significant. We do not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future nor a need to commence remedial activities at this time. However, a regulatory agency could require us to investigate and remediate any hydrocarbon contamination even while the gas plant remains in operation. In addition, we also own and operate the Fairway natural gas processing plant in the Gulf Coast Basin. As of December 31, 2014, we have recorded $9.0 million as future abandonment liability for the estimated cost for decommissioning the Elk Basin and Fairway natural gas processing plants. Due to the significant uncertainty associated with the known and unknown environmental liabilities at the gas plants, our estimate of the future abandonment liability includes a large reserve. Our estimates of the future abandonment liability and compliance costs are subject to change and the actual cost of these items could vary significantly from those estimates.
 
Water Discharges.   The Federal Water Pollution Control Act, as amended, or “Clean Water Act,” and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into state waters as well as waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the relevant state with delegated authority. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure, or “SPCC,” requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by an oil spill or release. If an oil spill or release were to occur as a result of our operations, we expect that it would be contained and remediated in accordance with our SPCC plan together with the assistance of trained first responders and any oil spill response contractor that we may have engaged to address such spills and releases. The Clean Water Act and analogous state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges.

Fluids associated with oil and natural gas production, consisting primarily of salt water, are disposed by injection in below ground disposal wells. These disposal wells are regulated pursuant to the Underground Injection Control, or UIC, program

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established under the federal Safe Drinking Water Act, or SDWA, and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While we believe that our disposal well operations substantially comply with requirements under the UIC program, a change in disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations. For example, there exists a growing concern that the injection of saltwater and other fluids into below ground disposal wells triggers seismic activity in certain areas, including Texas, where we operate. In response to these concerns, in October 2014, the Texas Railroad Commission, or TRC, published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs.

The Oil Pollution Act of 1990, as amended, or “OPA,” amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that are the site of a release of oil into waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. We believe we are in substantial compliance with the Clean Water Act, OPA and analogous state laws.

Hydraulic Fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions and other similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the BLM issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015.

From time to time Congress has considered adopting legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, some states in which the Company operates, including Montana, North Dakota, Texas and Wyoming, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, as the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
 
In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Also, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in the first half of 2015. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing activities.
 

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To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability and control of well insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Air Emissions.   The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from sources through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and their implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to result in the emission of new or increased existing air pollutants, obtain and strictly comply with air permit requirements containing various emissions and operational limitations, or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. To date, we believe that no significant difficulties have been encountered in obtaining air permits. Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air control equipment in connection with obtaining and maintaining operating permits and approvals for emissions of pollutants. For example, in December 2014, the EPA published a proposed regulation that it expects to finalize by October 1, 2015, which rulemaking proposed to revise the National Ambient Air Quality Standard, or “NAAQS,” for ozone between 65 to 70 parts per billion, or “ppb,” for both the 8-hour primary and secondary standards. The current primary and secondary ozone standards are set at 75 ppb. The EPA also requested public comments on whether the standard should be set as low as 60 ppb or whether the existing 75 ppb standard should be retained. If the EPA lowers the ozone standard, states could be required to implement new more stringent regulations, which could apply to our operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

Activities on Federal Lands.  Oil and natural gas exploitation and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or “NEPA.” NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Our current production activities, as well as proposed development plans, on federal lands require governmental permits or similar authorizations that are subject to the requirements of NEPA. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Climate Changes.  In response to findings made by the EPA that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climatic changes, the EPA has adopted regulations under existing provisions of the Clean Air Act that establish Title V operation and Prevention of Significant Deterioration, or “PSD,” construction permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which typically will be established by the states. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities in the United States on an annual basis, which include certain of our operations. We are conducting monitoring of GHG emissions from certain of our operations in accordance with the GHG emissions reporting rule and we believe that our monitoring and reporting activities are in substantial compliance with applicable reporting obligations.

While from time to time Congress has considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. For example, pursuant to President Obama’s Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015, that EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities

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as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations. Still other scientists have concluded the earth is entering a new "Maunder Minimum," characterized by reduced solar activity which will materially cool the earth for some decades to come, producing related significant physical effect such as increased frequency of cold snaps, shortened growing seasons, and extensive periods of heavy freezing and other climatic events. If such effects were to occur, they could have an adverse effect on the provision of our production.

Endangered Species Act Considerations.  The federal Endangered Species Act, as amended, or “ESA,” restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities or leased acreage may be located in areas that are designated as habitat for endangered or threatened species, we believe our operations are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required.  Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service, or “FWS,” is required to make a determination on listing of numerous species as endangered or threatened under the ESA through the agency’s 2017 fiscal year.  The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. For example, on March 27, 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico, Colorado and Oklahoma, where we conduct operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies, or WAFWA, pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to us from species protection measures, time delays or limitations on the drilling program’s activities, which costs, delays or limitations may be significant to our business.

Occupational Safety and Health.  We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we maintain and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
  
Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules, orders and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. For example, on July 1, 2014, the North Dakota Industrial Commission adopted Order No. 24665, or the “July 2014 Order,” pursuant to which the agency adopted legally enforceable “gas capture percentage goals” targeting the capture of 74% of natural gas produced in the State by October 1, 2014, 77% percent of such gas by January 1, 2015, 85% of such gas by January 1, 2016 and 90% of such gas by October 1, 2020. The July 2014 Order establishes an enforcement mechanism for policy recommendations that were previously adopted by the North Dakota Industrial Commission in March 2014. Those recommendations required all exploration and production operators applying for new drilling permits in the state after June 1, 2014 to develop Gas Capture Plans that provide measures for reducing the amount of natural gas flared by those operators so as to be consistent with the agency’s now-implemented gas capture percentage goals. In particular, the July 2014 Order provides that after an initial 90-day period, wells must meet or exceed the North Dakota Industrial Commission’s gas capture percentage goals on a per-well, per-field, county, or statewide basis. Failure to comply with the gas capture percentage goals will result in an operator having to restrict its production to 200 barrels of oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or 100 barrels of oil per day if less than 60% of such monthly volume of natural gas is captured. While we believe that we were in compliance with these requirements as of December 31, 2014 and expect to remain in compliance in the future, there is no assurance that we will be able to remain in

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compliance in the future or that such future compliance will not have a material adverse effect on our business and operation results. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
 
Drilling and Production.   Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:
 
the location of wells;

the method of drilling and casing wells;

the surface use and restoration of properties upon which wells are drilled;

the plugging and abandoning of wells; and

notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil, natural gas and NGLs we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
 
Regulation of Transportation and Sales.   The availability, terms and cost of transportation significantly affect sales of oil, natural gas and NGLs. The interstate transportation of natural gas is subject to federal regulation primarily by the Federal Energy Regulatory Commission, or “FERC,” under the Natural Gas Act of 1938, or “NGA.”  FERC regulates interstate natural gas pipeline transportation rates and service conditions, which may affect the marketing and sales of natural gas.  FERC requires interstate pipelines to offer available firm transportation capacity on an open-access, non-discriminatory basis to all natural gas shippers.  FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry.  State laws and regulations generally govern the gathering and intrastate transportation of natural gas. Natural gas gathering systems in the states in which we operate are generally required to offer services on a non-discriminatory basis and are subject to state ratable take and common purchaser statutes.  Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling.  Similarly, common purchaser statutes generally require gatherers to purchase without discrimination in favor of one producer over another producer or one source of supply over another source of supply.

The ability to transport oil and NGLs is generally dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act, or subject to regulation by the particular state in which such transportation takes place.  Laws and regulation applicable to pipeline transportation of oil largely require pipelines to charge just and reasonable rates published in agency-approved tariffs and require pipelines to provide non-discriminatory access and terms and conditions of service. The justness and reasonableness of interstate oil and natural gas liquid pipeline rates can be challenged at FERC through a protest or a complaint and, if such a protest or complaint results in a lower rate than that on file, pipeline shippers may be eligible to receive refunds or, in the case of a complaining shipper, reparations for the two-year period prior to the filing of the complaint. Certain regulations imposed by FERC, by the United States Department of Transportation and by other regulatory authorities on pipeline transporters in recent years could result in an increase in the cost of pipeline transportation service.  We do not believe, however, that these regulations affect us any differently than other producers.

Under the Energy Policy Act of 2005, or “EPAct 2005,” Congress made it unlawful for any entity, as defined in the EPAct 2005, including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services regulated by the FERC that violates the FERC’s rules. FERC’s rules implementing EPAct 2005 make it unlawful for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or

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deceit upon any person in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act up to $1,000,000 per day per violation. Pursuant to authority granted to FERC by EPAct 2005, FERC has also put in place additional regulations intended to prevent market manipulation and to promote price transparency.  For example, FERC has imposed new rules discussed below requiring wholesale purchasers and sellers of natural gas to report to FERC certain aggregated volume and other purchase and sales data for the previous calendar year. While EPAct 2005 reflects a significant expansion of the FERC’s enforcement authority, we do not anticipate that we will be affected by EPAct 2005 any differently than energy industry participants.

In 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report on Form No. 552, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Pursuant to Order 704, we may be required to annually report to FERC, starting May 1 of each year, information regarding natural gas purchase and sale transactions depending on the volume of natural gas transacted during the prior calendar year.

On August 6, 2009, the Federal Trade Commission, or “FTC,” issued a Final Rule prohibiting manipulative and deceptive conduct in the wholesale petroleum markets. The Final Rule applies to transactions in crude oil, gasoline, and petroleum distillates. The FTC promulgated the Final Rule pursuant to Section 811 of the Energy Independence and Security Act of 2007, or “EISA,” which makes it unlawful for anyone, in connection with the wholesale purchase or sale of crude oil, gasoline or petroleum distillates, to use any “manipulative or deceptive device or contrivance, in contravention of such rules and regulations as the Federal Trade Commission may prescribe.” The Final Rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale, from: (a) knowingly engaging in any act, practice, or course of business – including making any untrue statement of material fact that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other natural gas companies with whom we compete.

The price at which we buy and sell natural gas is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. Sales of condensate and NGLs are not currently regulated and are made at market prices. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission, or “CFTC.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities. 

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

State Regulation.  The various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGLs, including imposing severance and other production-related taxes and requirements for obtaining drilling permits. Reduced rates or credits may apply to certain types of wells and production methods.

States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not currently regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil, natural gas and NGLs that may be produced from our wells,

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to increase our cost of production, to limit the number of wells or locations we can drill and to limit the availability of pipeline capacity to bring our products to market.

In addition to production taxes, Texas, Oklahoma and Montana each impose ad valorem taxes on oil and natural gas properties and production equipment. Wyoming and New Mexico impose an ad valorem tax on the gross value of oil and natural gas production in lieu of an ad valorem tax on the underlying oil and natural gas properties. Wyoming also imposes an ad valorem tax on production equipment. North Dakota imposes an ad valorem tax on gross oil and natural gas production in lieu of an ad valorem tax on the underlying oil and gas leases or on production equipment used on oil and gas leases.

The petroleum industry participants are also subject to compliance with various other federal, state and local regulations and laws. Some of these regulations and those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these regulations and laws will have a material adverse effect upon the unitholders.

Federal, State or Native American Leases.  Our operations on federal, state, or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the BLM and other agencies. For example, in May 2013, the BLM published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. The BLM is expected to promulgate a final rule in the first half of 2015.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards and other potential events that can adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation or leasehold acquisitions or result in loss of properties.

In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. We do not carry business interruption insurance except for our Elk Basin and Fairway gas plants as well as for our Piceance compressor assets. We may not obtain insurance for certain risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost.  If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.

Employees

As of February 25, 2015, we had 260 full-time employees. We also contract for the services of independent consultants involved in land, regulatory, tax, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.
 
Offices
 
Our principal executive office is located at 5847 San Felipe, Suite 3000, Houston, Texas 77057. Our main telephone number is (832) 327-2255.

Available Information
 
Our website address is www.vnrllc.com. We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Annual Report. We make available on our website under “Investor Center-SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. The SEC also maintains a website at www.sec.gov that contains reports, proxy statements and other information regarding SEC registrants, including us.

You may also find information related to our corporate governance, board committees and company code of business conduct and ethics on our website. Among the information you can find there is the following:
 

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• Audit Committee Charter;

• Nominating and Corporate Governance Committee Charter;

• Compensation Committee Charter;

• Conflicts Committee Charter;

• Code of Business Conduct and Ethics; and

• Corporate Governance Guidelines.

ITEM 1A.  RISK FACTORS

Risks Related to Our Business

We may not have sufficient cash from operations to pay monthly distributions on our common units following establishment of cash reserves and payment of operating costs.
 
We may not have sufficient cash flow from operations each month to pay distributions.  Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our board of directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from month to month based on, among other things:
 
the amount of oil, natural gas and NGLs we produce;

the price at which we are able to sell our oil, natural gas and NGLs production;

the level of our operating costs;

the level and success of our price risk management activities;

the level of our interest expense which depends on the amount of our indebtedness and the interest payable thereon;

the level of our capital expenditures; and

voluntary or required payments on our debt agreements.


In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
 
the level of our capital expenditures;

our ability to make working capital borrowings under our financing arrangements to pay distributions;

the cost of acquisitions, if any;

our debt service requirements;

fluctuations in our working capital needs;

timing and collectibility of receivables;

prevailing economic conditions; and

the amount of cash reserves established by our board of directors for the proper conduct of our business.

As a result of these factors, the amount of cash we distribute in any month to our unitholders may fluctuate significantly from month to month. If we do not achieve our expected operational results or cannot borrow the amounts needed, we may not be able to pay the full, or any, amount of the monthly distributions, in which event the market price of our common units may decline substantially.

Growing the Company will require significant amounts of debt and equity financing, which may not be available to us on acceptable terms, or at all.

We plan to fund our growth through acquisitions with proceeds from sales of our debt and equity securities and borrowings under our Reserve-Based Credit Facility; however, we cannot be certain that we will be able to issue our debt and equity securities on terms or in the proportions that we expect, or at all, and we may be unable to refinance our Reserve-Based Credit Facility upon maturity.

A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our ability to remain in compliance with the financial covenants under our Reserve-Based Credit Facility which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or not pursue growth opportunities.

Our financing arrangements have substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations.
 
As of February 27, 2015, we had an aggregate amount of approximately $1.9 billion outstanding under our Reserve-Based Credit Facility, the Senior Notes and Lease Financing Obligations with additional borrowing capacity of approximately $634.5 million under our Reserve-Based Credit Facility. As a result of our indebtedness, we will use a portion of our cash flow to pay interest and principal when due, which will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate.

Our Reserve-Based Credit Facility and the Senior Notes contain certain covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates, as well as containing covenants requiring us to maintain certain financial ratios and tests.

Our borrowing base is the amount of money available for borrowing, as determined semi-annually by our lenders in their sole discretion. The lenders will re-determine the borrowing base based on an engineering report with respect to our oil, natural gas and NGLs reserves, which will take into account the prevailing oil, natural gas and NGLs prices at such time. In the future, we may not be able to access adequate funding under our Reserve-Based Credit Facility as a result of (i) a decrease in our borrowing

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base due to the outcome of a subsequent borrowing base redetermination or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations.

Continued declines in commodity prices could result in a redetermination lowering our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Reserve-Based Credit Facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid within 30 days, or in six monthly installments beginning within 30 days, or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our Reserve-Based Credit Facility.
 
Continued low oil, natural gas and NGLs prices and other factors have resulted, and in the future may result, in ceiling test or goodwill write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting to report our oil and natural gas properties. Under this method, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and natural gas properties may not exceed a “ceiling limit,” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write-down.” Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write-down would not impact cash flow from operating activities, but it could have a material adverse effect on our results of operations in the period incurred and would reduce our members’ equity.

In accordance with the guidance contained within ASC Topic 805, “Business Combinations,” (“ASC Topic 805”), upon the acquisition of oil and natural gas properties, the Company records an asset based on the measurement of the fair value of the properties acquired determined using forward oil and natural gas price curves at the acquisitions dates, which can have several price increases over the entire reserve life. As discussed above, capitalized oil and natural gas property costs are limited to a ceiling based on the present value of future net revenues, computed using a flat price for the entire reserve life equal to the historical 12-month average price, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write down capitalized costs to the ceiling. As a result, there is a risk that we will be required to record an impairment of our oil and natural gas properties if certain attributes exist, such as declining oil and natural gas prices.

We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2014 of $234.4 million as a result of a decline in realized oil and natural gas prices at the measurement date, December 31, 2014. Such impairment was recognized during the fourth quarter of 2014. The most significant factor affecting the 2014 impairment related to the properties that we acquired in the Piceance Acquisition. The fair value of the properties acquired (determined using forward oil and natural gas price curves at the acquisitions dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. The fourth quarter 2014 impairment was calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil.

We expect to record an additional impairment of our oil and natural gas properties during 2015 as a result of declining oil and natural gas prices. Based on the 11-month average oil, natural gas and NGLs prices through February 1, 2015 and if such prices do not change during March 2015, we estimate that, on a pro forma basis, we will record a ceiling test write down on our existing assets of approximately $530.9 million at March 31, 2015 and an additional write down of $562.4 million for the remainder of the year ending December 31, 2015. However, whether the amount of any such impairments will be similar in amount to such estimates, is contingent upon many factors such as the price of oil, natural gas and NGLs for the remainder of 2015, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and natural gas property acquisitions, which could increase, decrease or eliminate the need for such impairments.

Additionally, we have recorded goodwill which represents the excess of the purchase price over the estimated fair value of the net assets acquired in the ENP Purchase. Significant price declines could cause us to record an impairment of goodwill, which would be reflected as non-cash charge against current earnings.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.
 

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A principal component of our business strategy is to grow our asset base and production through the acquisition of oil and natural gas properties characterized by long-lived, stable production. The character of newly acquired properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. The changes in the characteristics and risk profiles of such new properties will in turn affect our risk profile, which may negatively affect our ability to issue equity or debt securities in order to fund future acquisitions and may inhibit our ability to renegotiate our existing credit facilities on favorable terms.

Our future distributions and proved reserves will be dependent upon the success of our efforts to prudently acquire, manage and develop oil and natural gas properties that conform to the acquisition profile described in this Annual Report.
 
In addition to ownership of the properties currently owned by us, unless we acquire properties in the future containing additional proved reserves or successfully develop proved reserves on our existing properties, our proved reserves will decline as the reserves attributable to the underlying properties are produced. In addition, if the costs to develop or operate our properties increase, the estimated proved reserves associated with properties will be reduced below the level that would otherwise be estimated. We will manage and develop our properties, and the ultimate value to us of such properties which we acquire will be dependent upon the price we pay and our ability to prudently acquire, manage and develop such properties. As a result, our future cash distributions will be dependent to a substantial extent upon our ability to prudently acquire, manage and develop such properties.
 
Suitable acquisition candidates may not be available on terms and conditions that we find acceptable, we may not be able to obtain financing for certain acquisitions, and acquisitions pose substantial risks to our businesses, financial conditions and results of operations. Even if future acquisitions are completed, the following are some of the risks associated with acquisitions, which could reduce the amount of cash available from the affected properties:

some of the acquired properties may not produce revenues, reserves, earnings or cash flow at anticipated levels;

we may assume liabilities, including environmental liabilities that were not disclosed or that exceed their estimates;

we may be unable to integrate acquired properties successfully and may not realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;

acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and

we may incur additional debt related to future acquisitions.

Oil, natural gas and NGLs prices are volatile and have decreased dramatically over the last quarter of 2014 and the beginning of 2015. Sustained lower prices of oil and natural gas could have a material adverse impact on us.
    
Our financial condition, profitability and future growth and the carrying value of our oil and natural gas properties depend substantially on prevailing oil, natural gas and NGLs prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Prices for oil and natural gas have decreased dramatically over the latter half of 2014.
    
The amount we are able to borrow under our senior revolving credit facility is subject to periodic redetermination based in part on current oil and natural gas prices and on changing expectations of future prices. Continued declines in oil and natural gas prices may result in a reduction in our borrowing base at the next redetermination. A reduction in our borrowing base could require us to repay any indebtedness in excess of the borrowing base. Additionally, the indentures governing our senior unsecured debt contain covenants limiting our ability to incur additional indebtedness unless we meet one of two alternative tests. The first test applies to all indebtedness and requires that, after giving effect to the incurrence of additional debt, our fixed charge coverage ratio (which is the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters) will be at least 2.0 to 1.0. The second test applies to borrowings under credit agreements and limits these borrowings to the greater of a fixed sum of $750 million and 30% of our adjusted consolidated net tangible assets, which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves. Lower oil and natural gas prices in the future could reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness. Lower prices may also reduce the amount of oil and natural gas that we can economically produce and have an adverse effect on the value of our properties, which may cause us to incur impairment charges under full cost accounting rules.

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Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility are:

the domestic and foreign supply of oil and natural gas;
the ability of members of the Organization of Petroleum Exporting Countries (“OPEC”) and other producing countries to agree upon and maintain oil prices and production levels;
social unrest and political instability, particularly in major oil and natural gas producing regions outside the United     States, such as the Middle East, and armed conflict or terrorist attacks, whether or not in oil or natural gas producing     regions;
the level of consumer product demand;
the growth of consumer product demand in emerging markets, such as China;
labor unrest in oil and natural gas producing regions;
weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and     natural gas;
the price and availability of alternative fuels;
the price of foreign imports;
worldwide economic conditions; and
the availability of liquid natural gas imports.
    
These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and natural gas.

Continued low prices or further declines in prices for oil, natural gas and NGLs prices would not only reduce our revenue, but could reduce the amount of oil, natural gas and NGLs that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. If the oil and gas industry continues to experience low prices or experiences significant further price declines, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms or make distributions to our unitholders, all of which can affect the value of our units.
 
A widening of commodity differentials and our inability to enter into hedge contracts for a sufficient amount of our production at favorable pricing could materially adversely impact our financial condition, results of operations and cash flows from operations.

Our crude oil, natural gas and NGLs are priced in the local markets where the production occurs based on local or regional supply and demand factors. The prices that we receive for our crude oil, natural gas and NGLs production are generally lower than the relevant benchmark prices, such as NYMEX, that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. We may not be able to accurately predict crude oil, natural gas and NGLs differentials.

Price differentials may widen in the future. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the mid-stream or downstream sectors of the industry, trade restrictions and governmental regulations. We may be adversely impacted by a widening differential on the products we sell. Our oil and natural gas hedges are based on WTI or natural gas index prices and the NGLs hedges are based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices, so we may be subject to basis risk if the differential on the products we sell widens from

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those benchmarks and we do not have a contract tied to those benchmarks. We have entered into fixed-price swaps derivative contracts to cover a portion of our NGLs production to reduce exposure to fluctuations in NGLs prices. Currently, we are unable to hedge widening oil differentials in certain operating areas. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive and our inability to enter into hedge contracts at favorable pricing and for a sufficient amount of our production could adversely affect our financial condition, results of operations and cash flows from operations in the future.

Our limited ability to hedge our NGLs production could adversely impact our net cash provided by operating activities and results of operations.

A liquid, readily available and commercially viable market for hedging NGLs has not developed in the same way that exists for crude oil and natural gas. The current direct NGLs hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits our ability to hedge our NGLs production effectively or at all. As a result, our net cash provided by operating activities and results of operations could be adversely impacted by fluctuations in the market prices for NGLs products.

Unless we replace our reserves, our existing reserves and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.
 
Producing oil and natural gas wells extract hydrocarbons from underground structures referred to as reservoirs. Reservoirs contain a finite volume of hydrocarbon reserves referred to as reserves in place. Based on prevailing prices and production technologies, only a fraction of reserves in place can be recovered from a given reservoir. The volume of the reserves in place that is recoverable from a particular reservoir is reduced as production from that well continues. The reduction is referred to as depletion. Ultimately, the economically recoverable reserves from a particular well will deplete entirely, and the producing well will cease to produce and will be plugged and abandoned. In that event, we must replace our reserves. Unless we are able over the long-term to replace the reserves that are produced, investors in our units should consider the cash distributions that are paid on the units not merely as a “distribution yield” on the units, but as a combination of both a return of capital and a return on investment. Investors in our units will have to obtain the return of capital invested out of cash flow derived from their investments in units during the period when reserves can be economically recovered. Accordingly, we give no assurances that the distributions our unitholders receive over the life of their investment will meet or exceed their initial capital investment.

Adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

Our properties are located in Wyoming, Colorado, Texas, New Mexico, Louisiana, Mississippi, Montana, Arkansas, Oklahoma and North Dakota. An adverse development in the oil and natural gas business of any of these geographic areas, such as in our ability to attract and retain field personnel or in our ability to comply with local regulations, could have an impact on our results of operations and cash available for distribution to our unitholders.

Our acquisition activities will subject us to certain risks.
 
We have expanded our operations through acquisitions. Any acquisition involves potential risks, including, among other things: the validity of our assumptions about reserves, future production, revenues and costs, including synergies; an inability to integrate successfully the businesses we acquire; a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; the assumption of unknown liabilities including, for example, historical spills or releases, losses or costs for which we are not indemnified or for which our indemnity is inadequate; the diversion of management’s attention to other business concerns; an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; the incurrence of other significant charges, such as impairment of recorded goodwill or other intangible assets, asset devaluation or restructuring charges; unforeseen difficulties encountered in operating in new geographic areas; an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes; and customer or key employee losses at the acquired businesses.
 
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed

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on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
 
If our acquisitions do not generate increases in available cash per unit, our ability to make cash distributions to our unitholders could materially decrease.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties, including timing of drilling and other scheduled operations activities, compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. In the past, we have changed our development plans for certain proved undeveloped reserves and expect future development plans may also change as the operators of our outside operated properties adjust their capital plans based on prevailing market conditions. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

The amount of cash that we have available for distribution to our unitholders depends primarily upon our cash flow and not our profitability.
 
The amount of cash that we have available for distribution depends primarily on our cash flow, including cash from reserves and working capital or other borrowings, and not solely on our GAAP net income, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may be able to pay distributions during periods when we incur net losses.
 
Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
 
No one can measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. We prepare our own estimates of proved reserves and engage DeGolyer and MacNaughton (“D&M”), an independent petroleum engineering firm, to audit a substantial portion of our reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, the calculation of estimated reserves requires certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs, any of which assumptions may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per MMBtu and oil prices declined by $6.00 per barrel, the standardized measure of our proved reserves as of December 31, 2014 would decrease from $3.0 billion to $2.3 billion, based on price sensitivity generated from an internal evaluation. Our standardized measure is calculated using unhedged oil and natural gas prices and is determined in accordance with the rules and regulations of the SEC. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our proved reserves that we disclose in our annual financial statements is not necessarily the same as the current market value of our estimated proved reserves.
 
We base the estimated discounted future net cash flows from our proved reserves using a 12-month average price and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as:
 
the volume, pricing and duration of our oil and natural gas hedging contracts;

supply of and demand for oil, natural gas and NGLs;


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actual prices we receive for oil, natural gas and NGLs;

our actual operating costs in producing oil, natural gas and NGLs;

the amount and timing of our capital expenditures;

the amount and timing of actual production; and

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to unitholders.
 
Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves and adversely affect our ability to make distributions to our unitholders.
 
The oil and natural gas industry is capital intensive. We have made and ultimately expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, natural gas and NGLs reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations and our financing arrangements. Our cash flow from operations and our access to capital are subject to a number of variables, including:
 
our proved reserves;

the level of oil, natural gas and NGLs we are able to produce from existing wells;

the prices at which our oil, natural gas and NGLs are sold; and

our ability to acquire, locate and produce new reserves.

If our revenues or the borrowing base under our Reserve-Based Credit Facility decrease as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels or to replace or add to our reserves. Our Reserve-Based Credit Facility restricts our ability to obtain new debt financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our Reserve-Based Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves and production and a reduction in our cash available for distribution.
 
Our business depends on gathering and compression facilities owned by third parties and transportation facilities owned by third-party transporters and we rely on third parties to gather and deliver our oil, natural gas and NGLs to certain designated interconnects with third-party transporters. Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere with our ability to market the oil, natural gas and NGLs we produce and could reduce our revenues and cash available for distribution.

The marketability of our oil, natural gas and NGLs production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties in the respective operating areas. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, compression or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a

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result, we may not be able to sell the oil and natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, compression and transportation facilities, could reduce our revenues and cash available for distribution.

Our sales of oil, natural gas and NGLs and other energy commodities, and related hedging activities, expose us to potential regulatory risks.

The FTC, FERC and CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil, natural gas and NGLs or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We are subject to FERC requirements related to our use of capacity on natural gas pipelines that are subject to FERC regulation. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.

Climate change legislation and regulatory initiatives restricting emissions of GHGs may adversely affect our operations, our cost structure, or the demand for oil and natural gas.

In response to findings made by the EPA that emissions of GHGs present an endangerment to public health and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climatic changes, the EPA, has adopted regulations under existing provisions of the Clean Air Act establishing Title V operating and PSD construction permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which typically will be established by the states. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities, should those facilities exceed threshold permitting levels of GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities in the United States on an annual basis, which include certain of our operations. While from time to time Congress has considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. For example, pursuant to President Obama’s Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015, that EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our provision of services. Still other scientists have concluded the earth is entering a new "Maunder Minimum," characterized by reduced solar activity which will materially cool the earth for some decades to come, producing related significant physical effect such as increased frequency of cold snaps, shortened growing seasons, and extensive periods of heavy freezing and other climatic events. If such effects were to occur, they could have an adverse effect on the provision of our production.


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The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant”. The Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects. The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make distributions. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act and regulations is to lower commodity prices. Any of these consequences could have material, adverse effect on us, our financial condition, and our results of operations.

We depend on certain key customers for sales of our oil, natural gas and NGLs. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs they purchase from us, or to the extent these customers cease to be creditworthy, our revenues and cash available for distribution could decline.
 
For the year ended December 31, 2014, sales of oil, natural gas and NGLs to Anadarko Petroleum Corporation, Marathon Oil Company, Cardinal Midstream LLC, Plains Marketing, LP and Bill Barrett Corporation accounted for approximately 19%, 12%, 9%, 7%, and 5%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2014 therefore accounted for 52% of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash available for distribution could decline.
 
We are subject to compliance with environmental and occupational safety and health laws and regulations that may expose us to significant costs and liabilities.
 
The operations of our wells are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, environmental protection, and the health and safety of employees.  These laws and regulations may impose numerous obligations on our operations including the acquisition of permits, including drilling permits, to conduct regulated activities; the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities; restriction of types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmental sensitive areas such as wetlands, wilderness regions and other protected areas; the imposition of substantial liabilities for pollution resulting from our operations; and the application of specific health and safety criteria addressing worker protection. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions.
 
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory, corrective action or remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose joint and several strict liability for costs required to clean up and restore sites where hazardous substances or wastes have been disposed of or otherwise

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released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property or natural resource damage allegedly caused by the release of hazardous substances or other waste products into the environment.
 
We may incur significant environmental costs and liabilities in the performance of our operations as a result of our handling petroleum hydrocarbons, hazardous substances and wastes, because of air emissions and wastewater discharges relating to our operations, and due to historical industry operations and waste disposal practices by us or prior operators or other third parties over whom we had no control. For example, an accidental release of petroleum hydrocarbons from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, property and natural resource damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. For example, in December 2014, the EPA published a proposed regulation that it expects to finalize by October 1, 2015, which rulemaking proposed to revise NAAQS for ozone between 65 to 70 ppb for both the 8-hour primary and secondary standards. The current primary and secondary ozone standards are set at 75 ppb. The EPA also requested public comments on whether the standard should be set as low as 60 ppb or whether the existing 75 ppb standard should be retained. If the EPA lowers the ozone standard, states could be required to implement new more stringent regulations, which could apply to our operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. We may not be able to recover some or any of these costs from insurance. Please read “Item 1. Business—Operations—Environmental and Occupational Health Safety Matters.”

Laws and regulations pertaining to threatened and endangered species could delay or restrict the Company's operations and cause it to incur substantial costs.

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. The FWS may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the FWS is required to make a determination on the listing of numerous species as endangered or threatened under the ESA before completion of the agency's 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where the Company conducts operations could cause the Company to incur increased costs arising from species protection measures or could result in limitations on its exploration and production activities that could have an adverse effect on the Company's ability to develop and produce reserves. For example, on March 27, 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico, Colorado and Oklahoma, where we conduct operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies, or WAFWA, pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to us from species protection measures, time delays or limitations on the drilling program’s activities, which costs, delays or limitations may be significant to our business.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, operating restrictions or delays, and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, and other similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit

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guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the BLM issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015.

From time to time Congress has considered adopting legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states in which we operate, including Montana, North Dakota, Texas and Wyoming, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, as the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Also, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in the first half of 2015. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing activities.

Locations that we or the operators of our properties decide to drill may not yield oil or natural gas in commercially viable quantities.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we or the operators of our properties drill dry holes or wells that are productive but do not produce enough to be commercially viable after drilling, operating and other costs. If we or the operators of our properties drill future wells that we identify as dry holes, our drilling success rate would decline and may adversely affect our results of operations and our ability to pay future cash distributions at expected levels.
 
Many of our leases are in areas that have been partially depleted or drained by offset wells.

Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of oil or natural gas in these areas.
 
Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, resulting in temporarily lower cash from operations, which may impact our ability to pay distributions.
 
Our prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, including future oil, natural gas and NGLs prices, the generation of additional seismic or geological information, the availability of drilling rigs and other factors, we may decide not to drill one or more of these prospects.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing leasehold acreage. As of December 31, 2014, we have identified 1,254 proved undeveloped drilling locations and over 3,931 additional drilling locations. These identified drilling locations represent a significant part of our strategy. The SEC’s reserve reporting rules include a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. To the extent that we do not drill these locations within five years of initial booking, they may not continue to qualify for classification as proved reserves, and we may be required to reclassify such reserves as unproved reserves. The reclassification of such reserves could also have a negative effect on the borrowing base under our Reserve-Based Credit Facility.

Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, drilling and operating costs and drilling results. In addition, we have not assigned any proved reserves to the over 3,931 unproved drilling locations we have identified and scheduled for drilling and

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therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business, financial position, results of operations and our ability to pay distributions.

Drilling for and producing oil, natural gas and NGLs are high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
 
Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
 
the high cost, shortages or delivery delays of equipment and services;

shortages of or delays in obtaining water for hydraulic fracturing operations;

unexpected operational events;

adverse weather conditions;

facility or equipment malfunctions;

title problems;

compliance with environmental and other governmental requirements;

unusual or unexpected geological formations;

loss of drilling fluid circulation;

formations with abnormal pressures;

environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

fires;

blowouts, craterings and explosions;

uncontrollable flows of oil, natural gas or well fluids; and

pipeline capacity curtailments.

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.
 
We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions to our unitholders.

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Our business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile, and we cannot predict the prices we will be able to realize for our production in the future. As a result, we may borrow, to the extent available, significant amounts under our Reserve-Based Credit Facility in the future to enable us to pay monthly distributions. Significant declines in our production or significant declines in realized oil, natural gas and NGLs prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.
 
If we borrow to pay distributions, we are distributing more cash than we are generating from our operations on a current basis. This means that we are using a portion of our borrowing capacity under our Reserve-Based Credit Facility to pay distributions rather than to maintain or expand our operations. If we use borrowings under our Reserve-Based Credit Facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our common units. If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce or suspend our distribution in order to avoid excessive leverage and debt covenant violations.
 
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
 
Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in some of our operating areas and as a result, we generally perform the majority of our drilling in these areas during the summer and fall months. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increased costs or delay our operations. Additionally, many municipalities impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This limits our access to these jobsites and our ability to service wells in these areas. Generally, but not always, oil is in higher demand in the summer for its use in road construction and natural gas is in higher demand in the winter for heating. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.
 
Our price risk management activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to pay distributions to our unitholders.
 
We enter into derivative contracts to reduce the impact of oil, natural gas and NGLs price volatility on our cash flow from operations. Currently, we primarily use fixed-price swaps, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices. Please read “Item 1. Business—Operations—Price Risk and Interest Rate Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
 
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:
 
a counterparty may not perform its obligation under the applicable derivative instrument;

there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.
 
We are exposed to trade credit risk in the ordinary course of our business activities.


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We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’, customers’ and counterparties’ liquidity and ability to make payments or perform on their obligations to us.  Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could reduce our ability to make distributions to our unitholders.

We depend on senior management personnel, each of whom would be difficult to replace.

We depend on the performance of Scott W. Smith, our President and Chief Executive Officer, Richard A. Robert, our Executive Vice President and Chief Financial Officer and Britt Pence, our Senior Vice President of Operations. We maintain no key person insurance for either Mr. Smith, Mr. Robert or Mr. Pence. The loss of any or all of Messrs. Smith, Robert and Pence could negatively impact our ability to execute our strategy and our results of operations.
 
We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.
 
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil, natural gas and NGLs prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.
 
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
 
Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, we could also be liable for personal injuries, property and natural resource damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
 
Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major regulatory requirement inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our profitability. At this time, we cannot predict the effect of this increase on our results of operations. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff. Please read “Item1. Business—Operations—Environmental and Occupational Health and Safety Matters” and “Item 1. Business—Operations—Other Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect us.
 
Shortages of drilling rigs, supplies, oilfield services, equipment and crews could delay our operations and reduce our cash available for distribution.
 

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Higher oil, natural gas and NGLs prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. In the past, we and other oil, natural gas and NGLs companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Sustained periods of lower oil, natural gas and NGLs prices could bring about the closure or downsizing of entities providing drilling services, supplies, oil field services, equipment and crews. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available for distribution.

Risks Related to Our Structure

We may issue additional units without unitholder approval, which would dilute their existing ownership interests.

We may issue an unlimited number of limited liability company interests of any type, including units, without the approval of our unitholders.
 
The issuance of additional units or other equity securities may have the following effects:
 
the proportionate ownership interest of unitholders in us may decrease;

the amount of cash distributed on each unit may decrease;

the relative voting strength of each previously outstanding unit may be diminished; and

the market price of the units may decline.

Our limited liability company agreement restricts the voting rights of unitholders owning 20% or more of our units.
 
Our limited liability company agreement restricts the voting rights of unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than persons who acquire such units with the prior approval of the board of directors, cannot vote on any matter. Our limited liability agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.
 
Our limited liability company agreement provides for a limited call right that may require unitholders to sell their units at an undesirable time or price.
 
If, at any time, any person owns more than 90% of the units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining units then outstanding at a price not less than the then-current market price of the units. As a result, unitholders may be required to sell their units at an undesirable time or price and therefore may receive a lower or no return on their investment. Unitholders may also incur a tax liability upon a sale of their units.

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.
 
Unlike a corporation, our limited liability company agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The Company pays distributions on monthly basis. The value of our units may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may have difficulty issuing more equity to recapitalize.

Our management may have conflicts of interest with the unitholders. Our limited liability company agreement limits the remedies available to our unitholders in the event unitholders have a claim relating to conflicts of interest.
 
Conflicts of interest may arise between our management on the one hand, and the Company and our unitholders on the other hand, related to the divergent interests of our management. Situations in which the interests of our management may differ from interests of our non-affiliated unitholders include, among others, the following situations:

our limited liability company agreement gives our Board of Directors broad discretion in establishing cash reserves for the

40




proper conduct of our business, which will affect the amount of cash available for distribution. For example, our management will use its reasonable discretion to establish and maintain cash reserves sufficient to fund our drilling program;

our management team, subject to oversight from our Board of Directors, determines the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuances of additional units and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders; and

affiliates of our directors are not prohibited under our limited liability company agreement from investing or engaging in other businesses or activities that compete with the Company.

The price of our common and cumulative preferred units could be subject to wide fluctuations and unitholders could lose a significant part of their investment.

During 2014, the quoted market prices of our common and cumulative preferred units fluctuated as follows:
 
 
Closing Low
 
Closing High
Common unit (VNR)
 
$
13.59

 
$
32.95

Series A Preferred unit (VNRAP)
 
$
17.72

 
$
27.10

Series B Preferred unit (VNRBP)
 
$
15.91

 
$
25.01

Series C Preferred unit (VNRCP)
 
$
16.30

 
$
24.94


The market prices of our common and cumulative preferred units are subject to fluctuations in response to a number of factors, most of which we cannot control, including:
 
fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;

changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry, including fluctuations in commodity prices;

changes in securities analysts’ recommendations and their estimates of our financial performance;

the public’s reaction to our press releases, announcements and our filings with the SEC;

changes in market valuations of similar companies;

departures of key personnel;

commencement of or involvement in litigation;

variations in our quarterly results of operations or those of other oil and natural gas companies;

variations in the amount of our monthly cash distributions; and

future issuances and sales of our units.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
 
Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Revised Limited Liability Company Act, or the “Delaware Act,” we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, members or unitholders who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the

41




distribution amount. A purchaser of common units who becomes a member or unitholder is liable for the obligations of the transferring member to make contributions to the limited liability company that are known to such purchaser of units at the time it became a member and for unknown obligations if the liabilities could be determined from our limited liability company agreement.
 
An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited liability company interests. Reduced demand for our units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.
 

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to material amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in our units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.
 
Despite the fact that we are organized as a limited liability company (“LLC”) under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement.  Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
 
If we were treated as a corporation for federal income tax purposes, we may pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and may likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit recognized by us would flow through to unitholders. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of VNR as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
 
Our LLC Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state, or local income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law on us. At the state level, several states have been evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are required to pay Texas franchise tax which is assessed on Texas sourced taxable margin defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. If any other state were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a

42




partnership for U.S. federal income tax purposes. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. However, it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the costs of any IRS contest will reduce our cash available for distribution.
 
We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
 
Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability which results from their share of our taxable income.
 
Tax gain or loss on disposition of our common units could be more or less than expected.

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income result in a decrease in the tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation deductions. In addition, because the amount realized includes a unitholder’s share of our liabilities, if a unitholders sells their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
 
Treatment of distributions on our Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of our Preferred Units than the holders of our common units.
The Company will treat distributions on the Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Preferred Units as ordinary income. Although a holder of Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, the company anticipates accruing and making the guaranteed payment distributions monthly. Otherwise, the holders of Preferred Units are generally not anticipated to share in the Company’s items of income, gain, loss or deduction. Nor will the Company allocate any share of its nonrecourse liabilities to the holders of Preferred Units.

A holder of Preferred Units will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the unitholder to acquire such Preferred Unit. Gain or loss recognized by a unitholder on the sale or exchange of a Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Preferred Units will not be allocated a share of the Company’s items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. Distributions to non-U.S. holders of the Preferred Units will be treated as “effectively connected income” (which will subject holders to U.S. net income taxation and possibly the branch profits tax) and will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. holders. If the amount of withholding exceeds the amount of federal income tax actually due, non-U.S. holders may be required to file

43




United States federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments for the use of capital to tax exempt investors is not certain. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning our Preferred Units.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning units that may result in adverse tax consequences to them.
 
Investments in units by tax-exempt entities, including employee benefit plans, IRAs and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Allocations and/or distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our units.
 
We treat each purchaser of our common units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations and accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are the subject of a securities loan (e.g. a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
 
Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.
 
We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing

44




two tax returns (and our unitholders receiving two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income.  In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination.  Our termination currently would not affect our classification as a partnership for federal income tax purposes but instead, we would be treated as a new partnership for federal income tax purposes.  If treated as a new partnership, we must make new tax election and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs.
 
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
 
The Fiscal Year 2016 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units. 

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
 
In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in Wyoming, Colorado, Texas, New Mexico, Louisiana, Mississippi, Montana, Arkansas, Oklahoma and North Dakota. Each of these states, other than Texas and Wyoming, imposes an income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns.

ITEM 1B.     UNRESOLVED STAFF COMMENTS
 
None.
 

ITEM 2.     PROPERTIES
 
A description of our properties is included in “Item 1. Business,” and is incorporated herein by reference.

We have office leases in Houston, Ft. Worth and Odessa, Texas; and Gillette, Wyoming. As of December 31, 2014, the lease for the Houston office covers approximately 37,156 square feet of office space with a term ending on February 29, 2020. Our leases for the Ft. Worth and Odessa offices cover approximately 7,315 square feet and 6,500 square feet of office space, respectively, and run through December 31, 2015 and June 30, 2019, respectively. In Wyoming, the lease for our Gillette office covers approximately 5,000 square feet with a lease term expiring on April 30, 2018. The total annual costs of our office leases for 2014 was approximately $1.6 million.

We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.
 
ITEM 3.     LEGAL PROCEEDINGS

We are defendants in certain legal proceedings arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

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ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II
 
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are traded on the NASDAQ under the symbol “VNR.” On February 25, 2015, there were 83,709,271 common units outstanding and approximately 436 unitholders, which does not include beneficial owners whose units are held by a clearing agency, such as a broker or a bank. On February 25, 2015, the market price for our common units was $17.67 per unit, resulting in an aggregate market value of units held by non-affiliates of approximately $1.4 billion. The following table presents the high and low sales price for our common units during the periods indicated.
 
 
 
Common Units
 
 
 
High
 
Low
 
2014
 
 
 
 
 
Fourth Quarter
 
$
27.72

 
$
12.57

 
Third Quarter
 
$
33.04

 
$
26.11

 
Second Quarter
 
$
32.21

 
$
29.26

 
First Quarter
 
$
31.50

 
$
29.11

 
2013
 
 

 
 

 
Fourth Quarter
 
$
29.75

 
$
27.13

 
Third Quarter
 
$
28.45

 
$
24.23

 
Second Quarter
 
$
29.93

 
$
27.08

 
First Quarter
 
$
29.64

 
$
26.21

 
 
Stock Performance Graph. The performance graph below compares total unitholder return on our common units, with the total return of the Standard & Poor’s 500 Index, or “S&P 500 Index,” and our Peer Group Index, a weighted composite of eight oil and natural gas production publicly traded partnerships. The partnerships included in our peer group are Linn Energy, LLC, BreitBurn Energy Partners, L.P., Legacy Reserves LP, EV Energy Partners, LP, Mid-Con Energy Partners, Memorial Production Partners LP and LRR Energy, L.P. We have selected the members in our peer group based on annual revenue, market capitalization, total assets, and areas of operation. Total return includes the change in the market price, adjusted for reinvested dividends or distributions, for the period shown on the performance graph and assumes that $100 was invested in VNR at the last reported sale price of units as reported by New York Stock Exchange ($5.90) on December 31, 2008, and in the S&P 500 Index and our peer group index on the same date.  The results shown in the graph below are not necessarily indicative of future performance. The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Exchange Act, each as amended, except to the extent that we specifically incorporate it by reference into such filing.

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12/31/08
 
12/31/09
 
12/31/10
 
12/31/11
 
12/31/12
 
12/31/13
 
12/31/14
Vanguard Natural Resources, LLC
 
$
100.00

 
$
437.94

 
$
641.68

 
$
645.04

 
$
671.10

 
$
831.58

 
$
465.67

Peer Group Index
 
$
100.00

 
$
214.44

 
$
342.52

 
$
284.44

 
$
275.84

 
$
285.35

 
$
131.38

S&P 500 Index
 
$
100.00

 
$
126.45

 
$
145.49

 
$
148.55

 
$
172.31

 
$
228.10

 
$
259.30

 
Distributions Declared. The following table shows the amount per unit, record date and payment date of the cash distributions we paid on each of our common units attributable to each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors. On February 17, 2015, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of January 2015 of $0.1175 per common and Class B unit, or $1.41 on an annualized basis, which will be paid on March 17, 2015 to Vanguard unitholders of record on March 2, 2015. This represents a reduction from the distribution attributable to the month of December 2014 of $0.21 per common and Class B unit, or $2.52 on an annualized basis.

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Cash Distributions
 
 
Per Unit
 
Record Date
 
Payment Date
2014
 
 
 
 
 
 
Fourth Quarter
 
 
 
 
 
 
December
 
$
0.2100

 
February 2, 2015
 
February 13, 2015
November
 
$
0.2100

 
January 2, 2015
 
January 14, 2015
October
 
$
0.2100

 
December 1, 2014
 
December 15, 2014
Third Quarter
 
 
 
 
 
 
September
 
$
0.2100

 
November 3, 2014
 
November 14, 2014
August
 
$
0.2100

 
October 1, 2014
 
October 15, 2014
July
 
$
0.2100

 
September 2, 2014
 
September 12, 2014
Second Quarter
 
 
 
 
 
 
June
 
$
0.2100

 
August 1, 2014
 
August 14, 2014
May
 
$
0.2100

 
July 1, 2014
 
July 15, 2014
April
 
$
0.2100

 
June 2, 2014
 
June 13, 2014
First Quarter
 
 
 
 
 
 
March
 
$
0.2100

 
May 1, 2014
 
May 15, 2014
February
 
$
0.2100

 
April 1, 2014
 
April 14, 2014
January
 
$
0.2075

 
March 3, 2014
 
March 17, 2014
2013
 
 

 
 
 
 
Fourth Quarter
 
 
 
 
 
 
December
 
$
0.2075

 
February 3, 2014
 
February 14, 2014
November
 
$
0.2075

 
January 2, 2014
 
January 15, 2014
October
 
$
0.2075

 
December 2, 2013
 
December 13, 2013
Third Quarter
 
 
 
 
 
 
September
 
$
0.2075

 
November 1, 2013
 
November 14, 2013
August
 
$
0.2075

 
October 1, 2013
 
October 15, 2013
July
 
$
0.2075

 
September 3, 2013
 
September 13, 2013
Second Quarter
 
 
 
 
 
 
June
 
$
0.2050

 
August 1, 2013
 
August 14, 2013
May
 
$
0.2050

 
July 1, 2013
 
July 15, 2013
April
 
$
0.2050

 
June 3, 2013
 
June 14, 2013
First Quarter
 
 
 
 
 
 
March
 
$
0.2025

 
May 1, 2013
 
May 15, 2013
February
 
$
0.2025

 
April 1, 2013
 
April 12, 2013
January
 
$
0.2025

 
March 1, 2013
 
March 15, 2013
 
Our limited liability company agreement requires that, within 90 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date. Available cash generally means, for any month ending prior to liquidation:

(a) the sum of:

(i)
all our and our subsidiaries’ cash and cash equivalents (or our proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly-owned) on hand at the end of that quarter; and

(ii)
all our and our subsidiaries’ additional cash and cash equivalents (or our proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly-owned) on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made subsequent to the end of such quarter,

(b)
 less the amount of any cash re