10-K 1 vnr-20151231x10k.htm 10-K 10-K



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, 2015
 
 
 
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 o
 
No x
 
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, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $1,262,296,407 based upon the closing price reported for such date on the NASDAQ Global Select Market.
 
As of March 3, 2016, 130,481,279 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 2016 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, 2015 (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, 2015.


 





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” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”).  All statements other than historical facts, including, without limitation, statements regarding the expected future reserves, production, financial position, business strategy, revenues, earnings, costs, capital expenditures and debt levels of us, and plans and objectives of management for future operations, are forward-looking statements.  When used in this Annual Report, words such as we “may,” “can,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “predict,” “project,” “foresee,” “believe,” “will” or “should,” “would,” “could,” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. It is uncertain whether the events anticipated will transpire, or if they do occur what impact they will have on our results of operations and financial condition.   Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results, the ability to generate sales, income or cash flow, to service debt or to resume cash distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine actual results are beyond our ability to control or predict. These risks and uncertainties include, but are not limited to:

risks relating to any of our unforeseen liabilities;

further declines in oil, natural gas liquids (“NGLs”) or natural gas prices;

the level of success in exploitation, development and production activities;

adverse weather conditions that may negatively impact development or production activities;

the timing of exploitation and development expenditures;

inaccuracies of reserve estimates or assumptions underlying them;

revisions to reserve estimates as a result of changes in commodity prices

impacts to financial statements as a result of impairment write-downs;

risks related to level of indebtedness and periodic redeterminations of the borrowing base under our credit agreements;

ability to comply with covenants contained in the agreements governing our indebtedness;

ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget;

ability to generate sufficient cash flows to resume cash distributions;

ability to obtain external capital to finance exploitation and development operations and acquisitions;

federal, state and local initiatives and efforts relating to the regulation of hydraulic fracturing;

failure of properties to yield oil or gas in commercially viable quantities;

uninsured or underinsured losses resulting from oil and gas operations;
inability to access oil and gas markets due to market conditions or operational impediments;

the impact and costs of compliance with laws and regulations governing oil and gas operations;

ability to replace oil and natural gas reserves;

any loss of senior management or technical personnel;

competition in the oil and gas industry;






risks arising out of hedging transactions;

the costs and effects of litigation;

sabotage, terrorism or other malicious intentional acts (including cyber-attacks), war and other similar acts that disrupt operations or cause damage greater than covered by insurance;

change to tax treatment; and

other risks described under the caption “Risk Factors” in this Annual Report on Form 10-K.

Reservoir 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 reservoir 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.

Unless expressly stated otherwise, forward-looking statements are based on the expectations and beliefs of our management, based on information currently available, concerning future events affecting us. Although we believe that these forward-looking statements are based on reasonable assumptions, they are subject to uncertainties and factors related to our operations and business environments, all of which are difficult to predict and many of which are beyond our control. Any or all of the forward-looking statements in this Annual Report on Form 10-K may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. The foregoing list of factors should not be construed to be exhaustive. Many factors mentioned in this Annual Report on Form 10-K, including the risks outlined under the caption “Risk Factors” will be important in determining future results, and actual future results may vary materially.

There is no assurance that the actions, events or results of the forward-looking statements will occur, or, if any of them do, when they will occur or what effect they will have on our results of operations, financial condition, cash flows or distributions. In view of these uncertainties, readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of their dates. Except as required by law, we do not intend to update or revise our 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 Operating, LLC (“VO”), VNR Finance Corp. (“VNRF”), Encore Clear Fork Pipeline LLC, Escambia Operating Co. LLC (“EOC”), Escambia Asset Co. LLC (“EAC”), Eagle Rock Energy Acquisition Co., Inc. (“ERAC”), Eagle Rock Upstream Development Co., Inc. (“ERUD”), Eagle Rock Energy Acquisition Partnership, L.P. (“ERAP”), Eagle Rock Energy Acquisition Co. II, Inc. (“ERAC II”), Eagle Rock Upstream Development Co. II, Inc. (“ERUD II”) and Eagle Rock Energy Acquisition Partnership II, L.P. (“ERAP II”).






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, 2015, we own properties and oil and natural gas reserves primarily located in ten operating basins:

the Green River Basin in Wyoming;

the Permian Basin in West Texas and New Mexico;

the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama;

the Anadarko Basin in Oklahoma and North Texas;

the Piceance Basin in Colorado;

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. For financial information regarding Vanguard, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

1




Organizational Structure

The following diagram depicts our organizational structure as of March 7, 2016:


Recent Developments

2015 Mergers

LRE Merger

On October 5, 2015, we completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), by and among us, Lighthouse Merger Sub, LLC, our wholly owned subsidiary (“LRE Merger Sub”), Lime Rock Management LP (“LR Management”), Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”), Lime Rock Resources C, L.P. (“LRR C”), Lime Rock Resources II-A, L.P. (“LRR II-A”), Lime Rock Resources II-C, L.P. (“LRR II-C”), and, together with LRR A, LRR B, LRR C, LRR II-A and LR Management, the “GP Sellers”), LRR Energy, L.P. (“LRE”) and LRE GP, LLC (“LRE GP”), the general partner of LRE.

Pursuant to the terms of the LRE Merger Agreement, LRE Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as our wholly owned subsidiary (the “LRE Merger”), and, at the same time, we acquired all of the limited liability company interests in LRE GP from the GP Sellers in exchange for common units representing limited liability company interests in Vanguard. Under the terms of the LRE Merger Agreement, each common unit representing interests in LRE (the “LRE common units”) was converted into the right to receive 0.550 newly issued Vanguard common units.


2




As consideration for the LRE Merger, Vanguard issued approximately 15.4 million common units valued at $123.3 million based on the closing price per Vanguard common unit of $7.98 at October 5, 2015 and assumed $290.0 million in debt. The debt assumed was extinguished using borrowings under the Company’s Reserve-Based Credit Facility following the close of the LRE Merger. The Vanguard common units issued include 12,320 Vanguard common units issued as consideration for our purchase of the limited liability company interests in LRE GP. As of December 31, 2015, based on internal reserve estimates, properties acquired in the LRE Merger had estimated total net proved reserves of 126.1 MMcfe, of which 49% was natural gas reserves and 85% was proved developed producing.

Following the closing of the LRE Merger, LRE merged with and into VO and LRE GP merged with and into VNG, and LRE and LRE GP ceased to exist.

Eagle Rock Merger

On October 8, 2015, we completed the transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”), by and among us, Talon Merger Sub, LLC, our wholly owned subsidiary (“Eagle Rock Merger Sub”), Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and Eagle Rock Energy GP, L.P. (“Eagle Rock GP”). Pursuant to the terms of the Eagle Rock Merger Agreement, Eagle Rock Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as our wholly owned subsidiary (the “Eagle Rock Merger”).

Under the terms of the Eagle Rock Merger Agreement, each common unit representing limited partner interests in Eagle Rock (“Eagle Rock common unit”) was converted into the right to receive 0.185 newly issued Vanguard common units or, in the case of fractional Vanguard common units, cash (without interest and rounded up to the nearest whole cent). We issued approximately 27.7 million Vanguard common units valued at $258.3 million based on the closing price of $9.31 at October 8, 2015 and assumed $156.6 million in debt in connection with the Eagle Rock Merger. The Company extinguished $122.3 million of the debt assumed using borrowings under its Reserve-Based Credit Facility following the close of the Eagle Rock Merger. As of December 31, 2015, based on internal reserve estimates, properties acquired in the Eagle Rock Merger had estimated total net proved reserves of 390.6 MMcfe, of which 52% was natural gas reserves and 65% was proved developed producing.

Following the closing of the Eagle Rock Merger, Eagle Rock and Eagle Rock GP merged with and into VO, and Eagle Rock and Eagle Rock GP ceased to exist.
Debt Exchange

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”) in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. The Senior Secured Second Lien Notes were issued to certain eligible holders of Senior Notes due 2020 who validly tendered and did not validly withdraw their Senior Notes due 2020 pursuant to the terms of our exchange offer. Interest on the Senior Secured Second Lien Notes is payable on February 15 and August 15 of each year, beginning on August 15, 2016. The Senior Secured Second Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31, 2019, we have not repurchased, redeemed or otherwise repaid in full all of the Senior Notes due 2020 outstanding at that time in excess of $50.0 million in aggregate principal amount and, to the extent we repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain indebtedness, if such indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023.

Proved Reserves

Our total estimated proved reserves at December 31, 2015 were 2,288.9 Bcfe, of which approximately 17% were oil reserves, 68% were natural gas reserves and 15% were NGLs reserves. Of these total estimated proved reserves, approximately 72% were classified as proved developed. At December 31, 2015, 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 $50.20 per barrel of crude oil, $2.62 per MMBtu for natural gas, and $16.14 per barrel of NGLs.

At December 31, 2015, we owned working interests in 14,459 gross (5,285 net) productive wells. Our operated wells accounted for approximately 56% of our total estimated proved reserves at December 31, 2015. Our average net daily production was 415,343 Mcfe/day for the year ended December 31, 2015 and was 511,119 Mcfe/day for the fourth quarter of 2015. Our average proved reserves-to-production ratio, or average reserve life, is approximately 12 years based on our total proved reserves as of December 31, 2015 and our fourth quarter 2015 annualized production.

3





Additionally, we own approximately 881,508 gross undeveloped leasehold acres surrounding our existing wells. As of December 31, 2015, we have identified 1,591 proved undeveloped drilling locations and over 5,013 other drilling locations on our leasehold acreage.

Business Strategies

Our primary business objective is to generate stable cash flows to allow 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, 2015, through certain of our subsidiaries, we own interests in oil and natural gas properties located in ten operating basins. The following table presents the production for the year ended December 31, 2015 and the estimated proved reserves for each operating area: 
 
 
2015 Net Production
 
 
 
 
 
 
Natural Gas
 
Oil
 
NGLs
 
Total
 
Net Estimated
Proved Reserves
 
PV-10 Value
 
 
(MMcf)
 
(MBbls)
 
(MBbls)
 
(MMcfe)
 
(MMcfe)
 
(in millions)
Green River Basin
 
41,431

 
364

 
796

 
48,394

 
684,194

 
$
340.7

Permian Basin
 
4,296

 
1,164

 
390

 
13,617

 
232,234

 
$
290.5

Gulf Coast Basin
 
6,886

 
589

 
403

 
12,838

 
264,336

 
$
288.6

Anadarko Basin
 
2,242

 
211

 
230

 
4,890

 
280,171

 
$
245.0

Piceance Basin
 
23,678

 
239

 
1,353

 
33,230

 
425,819

 
$
232.3

Big Horn Basin
 
217

 
884

 
98

 
6,107

 
89,125

 
$
139.1

Arkoma Basin
 
17,200

 
73

 
208

 
18,887

 
246,006

 
$
135.2

Williston Basin
 
188

 
472

 
5

 
3,051

 
27,272

 
$
34.4

Wind River Basin
 
2,930

 
12

 
6

 
3,040

 
23,944

 
$
11.6

Powder River Basin
 
7,547

 

 

 
7,547

 
15,832

 
$
5.1

Total
 
106,615

 
4,008

 
3,489

 
151,601

 
2,288,933

 
1,722.5

 

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 11,000 to 14,000 feet with similar depths in the adjacent Jonah field. Additionally, we have Green River Basin properties located in the Hay Reservoir, Great Divide, Siberia Ridge, Wamsutter, Echo Springs and Standard Draw fields in southwestern Wyoming. These gas/condensate fields produce from stacked cretaceous aged tight sandstones within the Lewis and Almond/Mesaverde intervals between 8,000 and 12,000 feet deep. Our properties located in south central Wyoming

4




in the Sierra Madre field produce predominately oil from fractured cretaceous aged Niobrara limestone (between 5,000 and 6,000 feet) and conventional Shannon sandstone (between 3,500 and 4,000 feet). As of December 31, 2015, our Green River Basin properties consisted of 126,420 gross (35,170 net) leasehold acres. During 2015, the Green River Basin properties produced approximately 48,394 MMcfe of which 86% was natural gas. At December 31, 2015, the properties had total proved reserves of approximately 684,194 MMcfe or 30% of our total estimated proved reserves at year end, of which 56% were proved developed and 87% 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. Our Permian Basin properties are located in several counties which extend from Eddy County, New Mexico to Eastland County, Texas and encompass hundreds of fields with multiple producing intervals. 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. These properties primarily produce at depths ranging from 2,000 feet to 12,000 feet. As of December 31, 2015, our Permian Basin properties consisted of 326,183 gross (250,715 net) leasehold acres. During 2015, our Permian Basin operations produced approximately 13,617 MMcfe, of which 68% was oil, condensate and NGLs. At December 31, 2015, these properties accounted for approximately 232,234 MMcfe or 10% of our total estimated proved reserves at year end, of which 93% were proved developed and 65% were oil, condensate and NGLs.

Gulf Coast Basin Properties

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

Production from our 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 approximately 9,000 to 11,000 feet. The Cotton Valley field is located in Webster Parish, Louisiana and produces from an average depth of 11,000 feet.

Our Alabaman properties include the Big Escambia Creek, Flomaton and Fanny Church fields located in Escambia County, Alabama. These fields produce from either the Smackover or Norphlet formations at depths ranging from approximately 15,000 to 16,000 feet. The Fanny Church field is located two miles east of Big Escambia Creek. The Flomaton field is adjacent to and partially underlies the Big Escambia Creek field and produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet. The Smackover and Norphlet reservoirs are sour gas condensate reservoirs which produce gas and fluids containing a high percentage of hydrogen sulfide and carbon dioxide. These impurities are extracted at the Company-operated Big Escambia Creek Treating facility and the effluent gas is further processed for the removal of natural gas liquids in the Big Escambia Creek Gas Processing facility. The operation of the wells and the facility is closely connected, and we are the largest owner and operator of the combined assets. In addition to selling condensate, natural gas, and NGLs, we also market elemental sulfur.

Most of our South Texas producing properties are located in Dewitt, Hidalgo, LaSalle, Live Oak and Webb Counties. Our average working interest is approximately 82%. 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.

Our East Texas producing properties include the Fairway (James Lime Unit) field in Henderson and Anderson counties, which is produced from an average depth of 10,000 feet. Other East Texas properties produce from the Smackover formation at an average depth of 13,500 feet and are located in Henderson, Rains, Van Zandt and Wood Counties.

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 60%. Our production is mainly oil that produces from the Hosston Formation from a depth ranging from approximately 13,000 feet to 15,000 feet. Our other Mississippi properties are located in Covington, Jasper, Clarke, Leflore, Jefferson Davis, Wayne and Walthall Counties.

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


5




As of December 31, 2015, our Gulf Coast Basin properties consisted of 206,693 gross (107,027 net) leasehold acres. During 2015, the Gulf Coast Basin properties produced approximately 12,838 MMcfe, of which 47% were oil, condensate and NGLs. At December 31, 2015, these properties accounted for approximately 264,336 MMcfe or 12% of our total estimated proved reserves at year end, of which 75% were proved developed and 53% were natural gas.

Anadarko Basin Properties

The Anadarko Basin consists of operated and non-operated properties in the Golden Trend field, Cana (Woodford) shale play, Verden field, and other fields located in the Anadarko Basin of western Oklahoma. Within the Anadarko Basin, our assets can generally be characterized by stratigraphic plays with multiple, stacked pay zones and more complex geology than our other operating areas. Properties in in the Anadarko Basin include mature fields with long production histories.

Our largest producing field in the region is the Golden Trend field, which extends across Grady, McClain and Garvin Counties in Oklahoma. The field is a large structural trap, discovered in 1947, that produces from the shallow Pennsylvanian Deese formation to the deep Ordovician Arbuckle formation. Most of our current production is from the Bromide formation and the “Big Four” interval consisting of the Viola, Hunton, Woodford and Sycamore formations. We typically drill through all these formations and perform multi-stage fracture stimulation completions in the Bromides and “Big Four” interval.

We have a significant ownership position in the expanding Cana (Woodford) shale, Springer shale and Southeast Cana shale plays in western Oklahoma. Our net acres in these plays extend across Canadian, Blaine, Dewey, Grady, Garvin, McClain and Stephens Counties in Oklahoma. The Cana and Southeast Cana Shale produce from horizontal wells drilled to vertical depths of 11,000 to 16,000 feet and extended with horizontal lateral lengths of approximately 5,000 to 10,000 feet. The horizontal laterals are fracture stimulated in multiple stages to optimize production from the shale reservoir.

As of December 31, 2015, our Anadarko Basin properties consisted of 221,121 gross (55,554 net) leasehold acres. During 2015, the Anadarko Basin properties produced approximately 4,890 MMcfe, of which 54% were oil, condensate and NGLs. At December 31, 2015, these properties accounted for approximately 280,171 MMcfe or 12% of our total estimated proved reserves at year end, of which 58% were proved developed and 57% were natural gas.

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 6,000 to 8,000 feet. As of December 31, 2015, our Piceance Basin properties consisted of 24,040 gross (16,075 net) leasehold acres. During 2015, our properties in the Piceance Basin produced approximately 33,230 MMcfe, of which 71% was natural gas. At December 31, 2015, the Piceance Basin properties accounted for approximately 425,819 MMcfe or 19% of our total estimated proved reserves at year end, of which 74% were proved developed and 74% 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 of our properties in the Elk Basin area, which includes the Embar-Tensleep, Madison and Frontier formations as discussed below.

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.


6




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 25% to 100% in our Big Horn Basin properties, which consisted of 24,512 gross (15,632 net) leasehold acres as of December 31, 2015. During 2015, our properties in the Big Horn Basin produced approximately 6,107 MMcfe, of which 87% was oil. At December 31, 2015, the Big Horn Basin properties accounted for approximately 89,125 MMcfe or 4% of our total estimated proved reserves at year end, of which 100% were proved developed and 96% 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, 2015, our Arkoma Basin properties consisted of 398,628 gross (185,668 net) leasehold acres. During 2015, the Arkoma Basin properties produced approximately 18,887 MMcfe, of which 91% was natural gas. At December 31, 2015, the properties had total proved reserves of approximately 246,006 MMcfe or 11% of our total estimated proved reserves at year end, of which 90% were proved developed and 89% 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, 2015, our Williston Basin properties consisted of 550,996 gross (71,960 net) leasehold acres. During 2015, the properties produced approximately 3,051 MMcfe, of which 93% was oil. Our Williston Basin properties had estimated proved reserves at December 31, 2015 of 27,272 MMcfe or 1% of our total estimated proved reserves at year end, of which 100% were proved developed and 95% 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, 2015, our Wind River Basin properties consisted of 188,018 gross (156,994 net) leasehold acres. During 2015, our Wind River Basin properties produced approximately 3,040 MMcfe, of which 96% was natural gas. At December 31, 2015, the properties had total proved reserves of approximately 23,944 MMcfe or 1% of our total estimated proved reserves, of which 100% were proved developed and 97% were natural gas.

Powder River Basin Properties

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, L.L.C.. As of December 31, 2015, our Powder River Basin properties consisted of 114,287 gross (66,866 net) leasehold acres. During 2015, the properties produced approximately 7,547 MMcfe, which was 100% natural gas. At December 31, 2015, the properties had total proved reserves of approximately 15,832 MMcfe or 1% of our total estimated proved reserves at year end, of which 100% were proved developed.

7





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, (“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 2015 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 taken in-kind and sold pursuant to a liquids purchase agreement. We market our Green River Basin residue natural gas into the Rockies market through the use of multiple pipeline connections. During 2015, we received the average NYMEX price less $0.66 per Mcf in the Green River Basin. Due to the decline in the ethane price which began in 2014 and has continued into 2016, the Granger Plant made an economic decision to reject ethane effective January 2015 and is expected to continue ethane rejection through 2016.

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, 2015, we received the average NYMEX price less $0.23 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 2015, we received the average WTI price less $5.33 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 Channel and Waha Gas index pricing which typically results in a discount to NYMEX prices. For the year ended December 31, 2015, we received the average NYMEX price plus $0.02 per Mcf.

Our Anadarko Basin production in Oklahoma 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. The lean natural gas is gathered by Enable Gathering & Processing LLC and sold to market at Enable Oklahoma Intrastate Transmission LLC’s West pool at the Panhandle, TX-Okla. index pricing. The high Btu gas is sold at the wellhead to various third party entities. The majority is sold to Oneok Field Services Company LLC and DCP Midstream LP under gas purchase contracts subject to percent of proceeds pricing for all products. During 2015, we received the average NYMEX price less $0.86 per Mcf in the Anadarko Basin.      

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 2015, we received the average NYMEX price less $1.04 per Mcf in the Piceance Basin.

8





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 2015, we received the average NYMEX price less $7.57 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 Targa Resources, Inc. natural gas processing complex. The processed natural gas is subject to a processing agreement with Targa Resources, Inc., 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, 2015, we received the average NYMEX price less $1.28 per Mcf.

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 2015, we received the average NYMEX price less $10.48 per barrel in the Williston Basin.

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 at our election. Our residue natural gas is sold into the Rockies market at the CIG index price while the NGLs are sold to a third-party natural gas processor pursuant to a processing agreement.

Our Powder River natural gas production is classified as 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 2015, we received the average NYMEX price less $0.56 per Mcf in the Wind River Basin while we received the average NYMEX price less $1.66 per Mcf in the Powder River 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, 2015, as estimated by our internal reservoir 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.
 

9




Reserve Data:
 
Estimated net proved reserves:
 
Crude oil (MMBbls)
64.1

Natural gas (Bcf)
1,554.2

NGLs (MMBbls)
58.4

Total (Bcfe)
2,288.9

Proved developed (Bcfe)
1,652.4

Proved undeveloped (Bcfe)
636.5

Proved developed reserves as % of total proved reserves
72
%
Standardized Measure (in millions) (1)(2)
$
1,722.5

Representative Oil and Natural Gas Prices (3):


Oil—WTI per Bbl
$
50.20

Natural gas—Henry Hub per MMBtu
$
2.62

NGLs—Volume-weighted average price per Bbl
$
16.14


(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 2015, 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 $50.20.
 

10




The following tables set forth certain information with respect to our estimated proved reserves by operating basin as of December 31, 2015:
 
 
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
 
335.1

 
3.0

 
5.2

 
384.1

 
261.2

 
2.4

 
4.1

 
300.1

 
684.2

Permian Basin
 
75.1

 
16.1

 
7.3

 
215.3

 
7.3

 
0.9

 
0.7

 
16.9

 
232.2

Gulf Coast Basin
 
92.0

 
11.3

 
6.4

 
198.4

 
47.4

 
2.6

 
0.5

 
65.9

 
264.3

Anadarko Basin
 
88.6

 
4.9

 
7.4

 
162.1

 
70.1

 
2.3

 
5.6

 
118.1

 
280.2

Piceance Basin
 
232.5

 
1.8

 
11.8

 
313.8

 
81.1

 
0.9

 
4.2

 
112.0

 
425.8

Big Horn Basin
 
4.1

 
12.3

 
1.9

 
89.1

 

 

 

 

 
89.1

Arkoma Basin
 
202.3

 
1.2

 
2.2

 
222.5

 
17.1

 

 
1.1

 
23.5

 
246.0

Williston Basin
 
1.3

 
4.3

 

 
27.3

 

 

 

 

 
27.3

Wind River Basin
 
23.2

 
0.1

 

 
24.0

 

 

 

 

 
24.0

Powder River Basin
 
15.8

 

 

 
15.8

 

 

 

 

 
15.8

Total
 
1,070.0

 
55.0

 
42.2

 
1,652.4

 
484.2

 
9.1

 
16.2

 
636.5

 
2,288.9


 

PV-10 Value (1)


Developed

Undeveloped

Total
Operating Basin

(in millions)
Green River Basin
 
$
265.8

 
$
74.9

 
$
340.7

Permian Basin
 
285.3

 
5.2

 
290.5

Gulf Coast Basin
 
242.5

 
46.1

 
288.6

Anadarko Basin
 
210.7

 
34.3

 
245.0

Piceance Basin

192.2

 
40.1

 
232.3

Big Horn Basin
 
139.1

 

 
139.1

Arkoma Basin

130.6

 
4.6

 
135.2

Williston Basin

34.4

 

 
34.4

Wind River Basin
 
11.6

 

 
11.6

Powder River Basin

5.1

 

 
5.1

Total

$
1,517.3

 
$
205.2

 
$
1,722.5

 
 
(1)
PV-10 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, PV-10 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 reservoir 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 reservoir engineers’ estimates of future net revenues from our properties, and the standardized measure thereof, were determined to be economically producible under existing economic

11




conditions, which requires the use of the unweighted arithmetic average first day of the month prices for the 12-month period ended December 31, 2015 for each product.

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 reservoir engineers to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither the reservoir 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 2015, we paid DeGolyer and MacNaughton (“D&M”) approximately $0.2 million for all reserve and economic evaluations.

Proved Undeveloped Reserves

Our proved undeveloped reserves at December 31, 2015, as estimated by our internal reservoir engineers, were 636.5 Bcfe, consisting of 9.1 MMBbls of oil, 484.2 Bcf of natural gas and 16.2 MMBbls of NGLs. Our proved undeveloped reserves decreased by 17.2 Bcfe during the year ended December 31, 2015, as compared to our proved undeveloped reserves as of December 31, 2014. The following table represents a summary of our proved undeveloped reserves activity during the year ended December 31, 2015:

 
Bcfe
PUDs at January 1, 2015
653.7

Acquisitions
123.4

Revisions of prior estimates
(62.2
)
Conversion to developed
(78.4
)
PUDs at December 31, 2015
636.5


Acquisitions. The decrease in our proved undeveloped reserves during 2015 was offset by an increase of 123.4 Bcfe which resulted primarily from our acquisitions of oil and natural gas properties completed during 2015. As described below, 34.5 Bcfe of our proved undeveloped reserves acquired during 2015 were drilled in place of proved undeveloped reserves scheduled to be drilled as part of our year end drilling program.
Revisions. The decrease in proved undeveloped reserves during 2015 resulted from (i) a decrease of 64.7 Bcfe due to changes in prices and (ii) a decrease of 69.6 Bcfe due to revisions in the timing of our drilling development plan, primarily in the Arkoma, Permian and Powder River Basins, and the re-allocation of drilling of capital expenditures to more promising drilling opportunities. These decreases were offset by a net increase of 72.1 Bcfe due to revisions of previous volume estimates and decreases in capital costs and lease operating expenses.
Conversions. During the year ended December 31, 2015, we developed approximately 78.4 Bcfe of our total proved undeveloped reserves booked as of December 31, 2014 through the drilling of 160 gross (10.62 net) wells. We also converted 41.3 Bcfe of volumes to proved developed producing which were not booked as proved undeveloped reserves at December 31, 2014. Approximately 34.5 Bcfe of these reserves were proved undeveloped reserves acquired during 2015 which were drilled during the year ended December 31, 2015. The remaining 6.8 Bcfe were attributed to reserves not recognized as proved undeveloped reserves in our December 31, 2014 reserve report.
Development Plans. We expect to spend approximately 68% 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, 2015, we spent $63.6 million or approximately 57% of our 2015 proved undeveloped reserves capital expenditures budget converting 100.1 Bcfe of proved undeveloped reserves recorded at December 31, 2014 of which 78.4 Bcfe was fully converted to the developed category and the remainder of which is in progress and expected to be converted in 2016. Based on our 2014 year-end reserve report, we expected to spend $110.9 million developing 101.9 Bcfe of proved undeveloped reserves during 2015. Our 2015 actual proved undeveloped reserves capital expenditures differed from our 2015 proved undeveloped reserves capital expenditures budget at

12




December 31, 2014 because during 2015, we spent $25.6 million converting 41.3 Bcfe of volumes to proved developed producing which were not booked as proved undeveloped reserves at December 31, 2014, of this, $15.2 million related to converting 34.5 Bcfe of volumes attributable to development drilling in Oklahoma on acreage acquired in the Eagle Rock Merger.
We historically approach the development of our undeveloped reserves at a measured pace, in order to hold our production rate fairly constant or slightly increasing. Our development plan for drilling proved undeveloped wells includes the drilling of 253 net wells before the end of 2020 at an estimated cost of $576.3 million. This development plan calls for the drilling of 22 net wells during 2016, 65 net wells during 2017, 70 net wells during 2018, 59 net wells during 2019 and 37 net wells during 2020. Additionally, the expected plan of development of our natural gas proved undeveloped reserves, which represent 76% of our total proved undeveloped reserves at December 31, 2015, over the next five years is as follows:
 
Percent of Natural Gas
Proved Undeveloped Reserves
Expected to be Converted
2016
11%
2017
30%
2018
26%
2019
21%
2020
12%
Total
100%

At December 31, 2015, 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, 2015 have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves.

Our development plan discussed above for drilling proved undeveloped wells represents the final investment decision to drill these proved undeveloped reserves at the time the applicable proved undeveloped reserves are booked. However, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as (i) changes in commodity prices, (ii) anticipated cash flows and projected rate of return, (iii) access to capital, (iv) new opportunities with better returns on investment that were not known at the time of the reserve report, (v) asset acquisitions and/or sales and (vi) actions or inactions of other co-owners or industry operators. As such, the relative proportion of total proved undeveloped reserves that we develop may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled proved undeveloped reserves development, in favor of projects with a more attractive rate of return, leading us to deviate from our original development plan.
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 since these leases have no proved undeveloped reserves assigned. As of December 31, 2015, approximately 94,530 net acres are scheduled to expire in future periods and no proved undeveloped reserves are scheduled to be drilled after expiration. Of the total expiring acreage approximately 14,051 net acres expire in 2016, 71,615 net acres expire in 2017, 3,460 net acres expire in 2018 and 5,404 net acres expire in 2020.

Reserve Estimation Process

Estimates of proved reserves at December 31, 2015 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 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.


13




We use technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, production data, well test data, geologic maps, electrical logs and radioactivity logs. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

Our reservoir 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, 2015, 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, 2015 covered producing areas containing 80.1% 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 reservoir 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 reservoir engineering group. The report prepared by D&M was developed utilizing geological and engineering data we provided. The report of D&M dated January 29, 2016, 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 years ended December 31, 2015 and 2014. None of our fields had proved reserves that were greater than 15% of our total proved reserves during 2013.

14




 
 
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, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pinedale (Green River Basin)
 
804

 
98,266

 
1,932

 
$
58.87

 
$
2.37

 
$
0.26

 
$
0.54

Mamm Creek (Piceance Basin)
 
649

 
58,764

 
3,701

 
$
49.30

 
$
1.96

 
$
12.18

 
$
0.43

All other fields
 
9,529

 
135,065

 
3,927

 
$
57.24

 
$
2.07

 
$
21.71

 
$
1.41

Total
 
10,982

 
292,095

 
9,560

 
$
56.89

 
$
3.13

 
$
13.68

 
$
0.96

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 other fields
 
8,462

53,695

137,632

84

4,047

45.11

$
82.26

 
$
3.39

 
$
33.76

 
$
1.36


(1)
Average daily production for 2015, 2014 and 2013 calculated based on 365 days and includes 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’s Discussion and Analysis of Financial Condition and Results of Operations-Year Ended December 31, 2015 Compared to Year Ended December 31, 2014” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Year Ended December 31, 2014 compared to Year Ended December 31, 2013.”

(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, 2015 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.
 

15




 
 
Natural Gas Wells
 
Oil Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Green River Basin
 
2,851

 
410

 
22

 
20

 
2,873

 
430

Permian Basin
 
1,089

 
688

 
3,176

 
1,096

 
4,265

 
1,784

Gulf Coast Basin
 
963

 
450

 
201

 
94

 
1,164

 
544

Anadarko Basin
 
1,092

 
221

 
351

 
57

 
1,443

 
278

Piceance Basin
 
1,183

 
1,030

 
3

 
3

 
1,186

 
1,033

Big Horn Basin
 
5

 
3

 
298

 
215

 
303

 
218

Arkoma Basin
 
1,763

 
373

 
222

 
18

 
1,985

 
391

Williston Basin
 
197

 
8

 
197

 
76

 
394

 
84

Wind River Basin
 
144

 
132

 
11

 
10

 
155

 
142

Powder River Basin
 
691

 
381

 

 

 
691

 
381

Total
 
9,978

 
3,696

 
4,481

 
1,589

 
14,459

 
5,285


Developed and Undeveloped Leasehold Acreage

The following table sets forth information as of December 31, 2015 relating to our leasehold acreage.
 
 
 
Developed Acreage (1)
 
Undeveloped Acreage (2)
 
Total Acreage (3)
 
 
Gross (4)
 
Net (5)
 
Gross (4)
 
Net (5)
 
Gross (4)
 
Net (5)
Green River Basin
 
60,730

 
24,837

 
65,690

 
10,333

 
126,420

 
35,170

Permian Basin
 
301,765

 
235,375

 
24,418

 
15,340

 
326,183

 
250,715

Gulf Coast Basin
 
184,486

 
94,364

 
22,207

 
12,663

 
206,693

 
107,027

Anadarko Basin
 
176,678

 
44,895

 
44,443

 
10,659

 
221,121

 
55,554

Piceance Basin
 
16,112

 
10,477

 
7,928

 
5,598

 
24,040

 
16,075

Big Horn Basin
 
23,392

 
14,559

 
1,120

 
1,073

 
24,512

 
15,632

Arkoma Basin
 
382,862

 
177,214

 
15,766

 
8,454

 
398,628

 
185,668

Williston Basin
 
65,270

 
35,280

 
485,726

 
36,680

 
550,996

 
71,960

Wind River Basin
 
22,989

 
21,026

 
165,029

 
135,968

 
188,018

 
156,994

Powder River Basin
 
65,106

 
37,868

 
49,181

 
28,998

 
114,287

 
66,866

Total
 
1,299,390

 
695,895

 
881,508

 
265,766

 
2,180,898

 
961,661

 
(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)
As of December 31, 2015, approximately 94,530 net acres are scheduled to expire in future periods and no proved undeveloped reserves are scheduled to be drilled after expiration. Of the total expiring acreage approximately 14,051 net acres expire in 2016, 71,615 net acres expire in 2017, 3,460 net acres expire in 2018 and 5,404 net acres expire in 2020.
 
(4)
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.

(5)
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.


16




Drilling Activity

The following is a description of the Company’s drilling and completion activities during the year ended December 31, 2015.

In the Green River Basin, we participated in the drilling of 164 gross wells and the completion of 121 gross wells in Sublette County in southwestern Wyoming. Our average working interest in these non-operated wells is 12.5%. These wells are directionally drilled from pads but are vertical through the 4,000 feet pay section. The average well depth is approximately 14,000 feet and is typically completed with 14 to 20 frac stages.

In the Gulf Coast Basin, we drilled and completed two vertical wells and one horizontal well in Claiborne Parish, Louisiana with a 100% working interest. The vertical wells were drilled to an average depth of 10,400 feet and the horizontal well was drilled to a depth of approximately 11,800 feet.

In the Anadarko Basin, we participated with a 7% working interest in the drilling of one horizontal well and in the completion of 24 horizontal wells (3.0 net) in the Cana shale, Southeast Cana shale and Golden Trend field in Oklahoma. These wells were drilled to vertical depths of 8,000 to 16,000 feet and extended with horizontal lateral lengths of approximately 5,000 to 10,000 feet. The wells completed were part of the properties acquired in the Eagle Rock Merger.

We have significantly reduced our capital expenditures budget for 2016. We currently anticipate a capital expenditures budget for 2016 of approximately $63.0 million, which is 44% less than the $112.6 million we spent in 2015. We expect to spend approximately 40% of the 2016 capital expenditures budget in the Green River Basin where we will participate as a non-operated partner in the drilling and completion of directional natural gas wells in the Pinedale Field. Additionally, we expect to spend approximately 21% of the 2016 capital expenditures budget in the Anadarko Basin on the newly acquired SCOOP and STACK assets, participating as a non-operated partner drilling standard length and extended length liquid rich horizontal gas and oil wells targeting the Woodford Shale and various stacked pay Mississippian reservoirs. The balance of the 2016 capital expenditures budget is related to recompletion and maintenance activities in our other operating areas. Due to our reduced capital spending in 2016 we anticipate our annual production will be 10% to 15% lower than our fourth quarter 2015 average daily production of 511,119 Mcfe per day.

The following table sets forth information with respect to wells completed during the years ended December 31, 2015, 2014 and 2013. 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,
 

2015

2014

2013
Gross wells:

 


 


 

Productive

169


215


78

Dry






Total

169


215


78

Net Development wells:

 

 


 

Productive

23.6


27.2


6.9

Dry






Total

23.6


27.2


6.9



17




Operations
 
Principal Customers

For the year ended December 31, 2015, sales of oil, natural gas and NGLs to Mieco Inc., Marathon Oil Company, ConocoPhillips, Plains Marketing, L.P. and Targa Resources, Inc. accounted for approximately 20%, 7%, 7%, 7% and 6%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2015 therefore accounted for 47% 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.

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 of Financial Condition 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. During the year ending December 31, 2016, our firm transportation contracts obligate us to deliver 97,300 MMBtu of natural gas per day.

18




Type of Arrangement
 
Pipeline System /Location
 
Deliverable Market
 
Gross Deliveries (MMBtu/d)
 
Term
Firm Transport
 
WIC Medicine Bow
 
Rocky Mountains
 
25,000
 
01/16 – 06/20
Firm Transport
 
Questar Pipeline
 
Rocky Mountains
 
12,000
 
01/16 – 10/16
Firm Transport
 
Colorado Interstate Gas
 
Rocky Mountains
 
8,200
 
01/16 – 06/17
Firm Transport
 
Cheyenne Plains
 
Midcontinent
 
9,000
 
01/16 – 05/17
Firm Transport
 
Cheyenne Plains
 
Midcontinent
 
5,000
 
06/17 – 05/18
Firm Transport
 
Rockies Express
 
Northeast
 
25,000
 
01/16 – 11/19
Firm Transport
 
Gulf Crossing Pipeline
 
Mississippi-Alabama
 
10,000
 
01/16 – 07/16
Firm Transport
 
Oasis Pipeline
 
Katy Hub
 
3,600
 
01/16 – 10/16
Firm Transport
 
East Tennessee Natural Gas
 
North Carolina
 
4,500
 
01/16 – 10/18

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 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. In addition, in the current commodity price environment, we are less likely to hedge future revenues to the same extent as our historical and existing hedging arrangements. As such, our revenues will become more susceptible to commodity price volatility as our commodity price hedges settle and are not replaced. 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.
 

19




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 Gulf Coast Basin, Piceance Basin and Big Horn 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 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. Our 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;


20




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, 2015, 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 2016 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 the “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 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.
 

21




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.

As of December 31, 2015, we have recorded $15.1 million for future remedial costs and abandonment liability for decommissioning the Big Escambia Creek, Elk Basin, and Fairway natural gas processing plants.

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, for which we have reserved abandonment costs.

We continue to operate a groundwater remediation project at our Big Escambia Creek gas plant. This release occurred when a prior owner operated the Big Escambia Creek gas plant. We are carrying out the cleanup under the supervision of the Alabama Department of Environmental Management, which has approved the risk assessment. We are currently evaluating alternative groundwater treatment technologies. Our current estimate of total remedial costs is no more than approximately $1.0 million.

Our estimates of the future remediation cost are subject to change, and the actual cost of these items could vary significantly from the above estimates. Due to the significant uncertainty associated with the known environmental liabilities at the gas plants, our estimate of the future abandonment liability includes a reserve.
 
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 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

22




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.

While hydraulic fracturing is typically regulated by state oil and natural gas commissions, and other similar state agencies, increased federal interest has arisen in recent years.

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.

Federal agencies have asserted regulatory authority over certain aspects of the process. The EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; issued in April 2015 a proposed rule that would establish 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 March 2015, the BLM issued a final rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands.

In addition, federal agency 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. In June 2015, the EPA released a draft assessment of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. 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.

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.
  
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.

23





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 October 2015, the EPA issued a final rule that strengthened the National Ambient Air Quality Standard, or “NAAQS,” for ozone from 75 parts per billion, or “ppb,” to 70 ppb for both the 8-hour primary and secondary standards. The lower ozone standard could result in states implementing 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 Change.  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 the 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 operations. Still other scientists have concluded the sun may be entering an extended period of low-activity similar to the Maunder Minimum of the “Little Ice Age”.  They believe this could have significant physical effects, such as increased periods of

24




extended cold including longer winters, shorter growing seasons and increased frequencies of cold snaps; if any such effects were to occur, they could have an adverse effect on our operations.

Endangered Species Act Considerations.  Various federal and state statutes prohibit certain actions that adversely affect endangered and their habitats, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act, and the Clean Water Act. 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 2018 fiscal year.  

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. If we were to cause harm to species or damages to wetlands, habitat or natural resources as a result of our operations, government entities or, at times, private parties could seek 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, the government could seek criminal penalties. 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.

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. 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. 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. We have been a party to a Conservation Easement governing nearly 50,000 of affected acreage pursuant to which we agree to adopt certain adaptive management principles and pay an acreage-based mitigation assessment. Calendar year 2016 is the final year during which we expect to pay such assessment.

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, 2015 and expect to remain in compliance in the future, there is no assurance that we will be able to remain in

25




compliance in the future or that such future compliance will not have a material adverse effect on our business and operational 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

26




fraud or 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. In recent years, FERC has also issued rules prohibiting anticompetitive behavior by multiple affiliates of the same entity in the natural gas capacity release market, issued a policy statement providing natural gas pipelines a cost-recovery mechanism to recoup capital expenditures made to modernize pipeline infrastructure, and issued a rule adopting reforms to its scheduling rules to improve coordination between the natural gas and electric markets.

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 and oil 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

27




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, 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.

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 March 3, 2016, we had 381 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 collective bargaining agreements. 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 under “Investor Center-Corporate Governance.” Among the information you can find there is the following:
 

28




•     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

Oil, natural gas and NGLs prices are volatile due to factors beyond our control and have decreased dramatically during 2015 and the beginning of 2016. Sustained lower prices or any further decline in prices of oil, natural gas and NGLs, 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.

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. During 2014, 2015 and the beginning of 2016, for example, oil, natural gas and NGLs prices decreased dramatically. The crude oil spot price per barrel during the years ended December 31, 2014 and 2015 ranged from a high of $107.95 to a low of $34.55 and the NYMEX natural gas spot price per MMBtu during the same period ranged from a high of $6.15 to a low of $1.76. NGLs prices also suffered a similar decline. As of February 29, 2016, the crude oil price per barrel was $32.74 and the NYMEX natural gas spot price per MMBtu was $1.62. This price decline impacted our operating results for the year ended December 31, 2015 and contributed to a reduction in our anticipated future capital expenditures. In addition, this decline resulted in a reduction in our estimated proved reserves and, as a result of this reduction, we recorded substantial impairments to our oil, natural gas and NGLs properties in the year ended December 31, 2015.

The prices for oil, natural gas and NGLs are volatile due to a variety of factors, including, but not limited to:

29





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 production levels which has an impact on oil prices;

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 and growth of consumer product demand;

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 and renewable energy sources;

the impact of the U.S. dollar exchange rates on commodity prices;

the price of foreign imports;

technological advances affecting energy consumption;

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, natural gas and NGLs.

Sustained lower prices or any further decline in prices of 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, cause us to delay or postpone our planned capital expenditures and result in further impairments to our oil and gas properties, all of which 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 resume cash distributions to our unitholders, all of which can affect the value of our units.

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.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development drilling plans, production data, economics and other factors, we may be required to write down the carrying value of our properties.

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

30




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, 2015 of $1.8 billion as a result of a decline in realized oil and natural gas prices at the respective measurement dates of March 31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015. Such impairment was recognized during each quarter of 2015 and was calculated based on 12-month average prices for oil and natural gas as follows:

 
Impairment Amount (in thousands)
Natural Gas ($ per MMBtu)
Oil
($ per Bbl)
First quarter 2015
$
132,610

$3.91
$82.62
Second quarter 2015
$
733,365

$3.44
$71.51
Third quarter 2015
$
491,487

$3.11
$59.23
Fourth quarter 2015
$
484,855

$2.62
$50.20
Total
1,842,317

 
 
 
The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2015 were declining oil and natural gas prices and the closing of the LRE Merger and Eagle Rock Merger. The fair value of the properties acquired (determined using forward oil and natural gas price curves on the acquisition dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices on the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions because generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges.

We expect to record an additional impairment of our oil and natural gas properties during 2016 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, 2016 and if such prices do not change during March 2016, we estimate that, on a pro forma basis, we will record a ceiling test write down on our existing assets of approximately $221.3 million at March 31, 2016 and an additional write down of $458.9 million for the remainder of the year ending December 31, 2016. If oil, natural gas and NGLs prices were to decline an additional 10% from their 11-month average through February 1, 2016, we estimate that, on a pro forma basis, we would record additional ceiling test write downs on our existing assets of approximately $504.0 million at March 31, 2016 and an additional write down of $388.2 million for the remainder of the year ending December 31, 2016. 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 2016, 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 Encore Energy Partners LP acquisition completed in December 2010 and the LRE Merger. Significant oil, natural gas and NGLs price declines could cause us to record an impairment of goodwill, which would be reflected as a non-cash charge against current earnings. We recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015. Based on further evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units.

We may not have sufficient cash from operations to resume the payment of monthly cash distributions on our common and Class B units, and we may not have sufficient funds to resume the payment of monthly cash distributions on our preferred units.
 
We have suspended cash distributions to the holders of our common and Class B units and preferred units in order to conserve cash, repay our debt under our Reserve-Based Credit Facility and improve our liquidity. 

31





We may not have sufficient available cash each month to resume distributions to our common and Class B unitholders. Under the terms of our limited liability company agreement, in the event that we elect to resume such monthly cash distributions to our common and Class B unitholders, 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, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our common and Class B unitholders.

The amount of cash we can distribute on our common and Class B 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 prices at which we are able to sell our oil, natural gas and NGLs production (which decreased significantly in 2015 and have continued to decrease in 2016);

the level of our operating costs;

the level of our price risk management activities; and

voluntary 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, but not limited to:
 
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, including the level of our interest expense which depends on the amount of our indebtedness and the interest payable thereon;

required payments on our debt agreements;

the success of our price risk management activities;

fluctuations in our working capital needs;

timing and collectability 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, we may not have sufficient available cash to resume our monthly cash distributions to our common and Class B unitholders. Even if we were able to resume a monthly cash distribution to these unitholders, the amount of available cash that we could distribute in any month to our unitholders may fluctuate significantly from month to month.

In addition, we may not have sufficient funds each month to resume distributions to our preferred unitholders. Furthermore, while the monthly preferred unit distributions on our preferred units are in arrears, we are restricted from making cash distributions on our common units, which in turn may cause the price of our common units to decline. If at any time the preferred unit distributions on any class of our preferred units become 18 months in arrears, whether consecutive or not, the holders of our preferred units will become entitled to elect two members of our board of directors, and the size of our board of directors will be increased to accommodate such change, if needed. The holders of our preferred units will be entitled to continue electing two members of our board of directors until we pay in full, or declare and set aside funds for the payment of, all unpaid distributions on the preferred units.


32




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 from the credit facility (the “Reserve-Based Credit Facility”) under our Third Amended and Restated Credit Agreement (the “Credit Agreement”); 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. In addition, we have limited borrowing capacity under our Reserve-Based Credit Facility; as of December 31, 2015, there was approximately $1.69 billion of outstanding borrowings and $107.5 million of borrowing capacity under the Reserve-Based Credit Facility, after reflecting a $4.5 million reduction in availability for letters of credit .

A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity, as well as disruptions in credit market and debt and equity capital market conditions 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.

The terms of our indebtedness include restrictions and financial covenants that could limit growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

The indentures governing our Senior Notes due 2020 and Senior Secured Second Lien Notes and our Reserve-Based Credit Facility impose significant operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:

resume distributions in respect of our common units and preferred units or make other restricted payments;

incur additional secured and unsecured indebtedness;

create liens;

engage in mergers or consolidations or sell or otherwise dispose of all or substantially all of our assets;

make certain dispositions and transfers of assets;

engage in transactions with affiliates;

make investments; and

refinance certain indebtedness.

In addition, our Reserve-Based Credit Facility contains a number of significant covenants that, among other things, restrict our ability to:

dispose of assets;

incur or guarantee additional indebtedness and issue certain types of preferred equity;

resume distributions in respect of our common units;

create liens on our assets;

enter into sale or leaseback transactions;

enter into specified investments or acquisitions;

repurchase, redeem or retire our capital stock or subordinated debt;


33




merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;

engage in specified transactions with subsidiaries and affiliates; or

pursue other corporate activities.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under the indentures governing our Senior Notes due 2020 and Senior Secured Second Lien Notes and our Reserve-Based Credit Facility. Our Reserve-Based Credit Facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Additionally, the indentures governing our Senior Notes due 2020 and Senior Secured Second Lien Notes 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 2.25 to 1.0. If our fixed coverage ratio falls below 2.25 to 1.0, the second test applies to borrowings under credit agreements and limits these borrowings to: (i) under our Senior Notes due 2020, the greater of (a) a fixed sum of $1.0 billion and (b) $475.0 million plus 35% 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, and (ii) under our Senior Secured Second Lien Notes, the greater of (a) a fixed sum of $1.8 billion and (b) $950.0 million plus 35% of our modified adjusted consolidated net tangible assets. 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. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Further declines in oil, and natural gas and NGLs prices, or a prolonged period of oil, natural gas and NGLs prices at existing levels, could eventually result in our failing to meet one or more of the financial covenants under our Reserve-Based Credit Facility, which could require us to finance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under the indentures referenced above or our Reserve-Based Credit Facility. A default under these agreements, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder. The accelerated debt would become immediately due and payable. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it, and, even if new financing were then available, it may not be on terms that are acceptable to us. Further, to the extent that we enter into additional transactions which result in the discharge of debt at a discount, the holders of our common units may be subject to income tax to the extent the cancellation of indebtedness income exceeds cumulative passive losses generated by Vanguard in prior years, if applicable. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.

We may not be able to generate sufficient cash flow to meet our debt service obligations.
 
As of March 3, 2016, we had an aggregate amount of approximately $2.3 billion outstanding under our Reserve-Based Credit Facility, Senior Notes due 2020, Senior Secured Second Lien Notes and Lease Financing Obligations with additional borrowing capacity of approximately $96.6 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 ability to make payments on our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and gas industry, general economic and financial conditions, the impact of legislative and regulatory actions on how we conduct our business and other factors, all of which are beyond our control.

We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as:

34





refinancing or restructuring our debt;

selling assets;

reducing or delaying acquisitions or our drilling program; or

seeking to raise additional capital.

However, we cannot assure you that we would be able to refinance or restructure our debt or implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that implementing any such alternative financing plans would allow us to meet our debt obligations. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.

Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financings, could materially and adversely affect our business, financial condition, results of operations and prospects.

The borrowing base under our Reserve-Based Credit Facility 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 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. In June 2015, our lenders reduced the borrowing base under our Reserve-Based Credit Facility from $2.0 billion to $1.6 billion, although the borrowing base was automatically increased to $1.8 billion upon the closing of the LRE Merger. Our next borrowing base redetermination is scheduled for April 2016. Based on projected market conditions, continued declines in oil and natural gas prices and as existing hedges roll off, we expect a reduction in our borrowing base at the next scheduled redetermination. The precise amount of the reduction is not known at this time but we do expect that the amount will be significant.

Continued declines in commodity prices could result in future redeterminations that further reduce our borrowing base 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.

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, or we may be outbid by competitors. If we are unable to acquire properties containing additional proved reserves, our total level of additional proved reserves will decline as a result of our production, and we will be limited in our ability to pay cash distributions to our unitholders. Even if future acquisitions are completed, they may pose substantial risks to our businesses, financial conditions and results of operations.


35




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, changes 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 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 resume or sustain 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 depleted through production, 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 resume distributions to our unitholders.

Our properties are located in Wyoming, Colorado, Texas, New Mexico, Louisiana, Mississippi, Montana, Arkansas, Oklahoma, North Dakota and Alabama. 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 a negative impact on our results of operations and cash available for distribution to our unitholders.

Our acquisition activities will subject us to certain risks.

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. We have therefore historically expanded our operations through acquisitions.

36





Any acquisition involves potential risks, including, but not limited to, the following, which could reduce the amount of cash available from the affected properties:

the validity of our assumptions about reserves, future production, revenues and costs, including synergies;

unforeseen difficulties encountered in operating in new geographic areas;

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, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

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 decrease our liquidity by using a significant portion of our available cash or borrowings to finance acquisitions;

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

an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

we may incur a significant increase in our interest expense or financial leverage if we incur additional debt related to future acquisitions;

an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes;

customer or key employee losses at the acquired businesses; and

acquisitions could cause other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charge.
 
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 on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
 
For example, the realized success of the LRE Merger and Eagle Rock Merger will depend, in part, on our ability to realize the anticipated benefits and synergies from combining our business with the business of LRE and Eagle Rock. To realize these anticipated benefits, the businesses must be successfully combined. If the combined entity is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the anticipated benefits of the LRE Merger and Eagle Rock Merger may not be realized fully or at all. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the mergers.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
 
Borrowings under our Reserve-Based Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. If interest rates on our facility increased by 10%, interest expense for the year

37




ended December 31, 2015 would have increased by approximately $0.4 million. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risks” included under Part II of this annual report for further information regarding interest rate sensitivity.

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. As of December 31, 2015, we operated approximately 56% of our production and non-operated wells represented approximately 44% of our owned net wells. 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 resume the payment of distributions even when we record net income, and we may be able to resume the payment of 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 reservoir 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 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, to illustrate the impact of a sustained low commodity price environment, we present the following two examples: (1) if we reduced the 12-month average price for natural gas by $1.00 per MMBtu and if we reduced the 12-month average price for oil by $6.00 per barrel, while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of December 31, 2015 would decrease from 2,288.9 Bcfe to 2,061.3 Bcfe, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices were $2.57 per MMBtu (or a $0.05 price decrease from the 12-month average price of $2.62) and oil prices were $44.28 per barrel (or a $5.92 price decline from the 12-month average price of $50.20), while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of December 31, 2015 would increase from 2,288.9 Bcfe to 2,324.1 Bcfe. The preceding assumed prices in example (2) were derived from the 5-year New York Mercantile Exchange (NYMEX) forward strip price at February 29, 2016. 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.


38




The PV-10 of our proved reserves at December 31, 2015 may not be the same as the current market value of our estimated oil, natural gas and NGLs reserves.
 
You should not assume that the present value of future net reserves (“PV-10”) value of our proved reserves as of December 31, 2015 is the current market value of our estimated oil, natural gas and NGLs reserves. We base the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:
 
the actual prices we receive for oil, natural gas and NGLs;

our actual development and production 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 and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating PV-10 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. Actual future prices and costs may differ materially from those used in the present value estimates included in this annual report, which could have a material effect on the value of our reserves. The oil and natural gas prices used in computing our PV-10 as of December 31, 2015 under SEC guidelines were $50.20 per barrel of crude oil and $2.62 per MMBtu for natural gas, respectively, before price differentials.

Using more recent prices in estimating proved reserves would result in a reduction in proved reserve volumes because they are lower than the prices used in estimated proved reserves and due to economic limits, which would further reduce the PV-10 value of our proved reserves.
 
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 resume 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, but not limited to:
 
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. In turn, we may not be able to resume or sustain any distributions without making accretive acquisitions or capital expenditures that 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.
 

39




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 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.

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, 2015, sales of oil, natural gas and NGLs to Mieco Inc., Marathon Oil Company, ConocoPhillips, Plains Marketing, L.P. and Targa Resources, Inc. accounted for approximately 20%, 7%, 7%, 7%, and 6%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2015 therefore accounted for 47% 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.

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 resume 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.

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

40




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.

The third parties on whom we rely for gathering, compression and transportation services are subject to complex federal, state and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
 
The operations of the third parties on whom we rely for gathering, compression and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to resume distributions to our unitholders.

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 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. Please read “Item 1. Business-Operations-Environmental and Occupational Health Safety Matters.”

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.


41




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. 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.

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. Please read “Item 1. Business-Operations-Environmental and Occupational Health Safety Matters-Climate Change.” 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.

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.

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 sun may be entering an extended period of low-activity similar to the Maunder Minimum of the “Little Ice Age”.  They believe this could have significant physical effects, such as increased periods of extended cold including longer winters, shorter growing seasons and increased frequencies of cold snaps; if any such effects were to occur, they could have an adverse effect on our operations.

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 2012. However, the CFTC introduced new rules in 2013 that would place position limits on future and option contracts and for swaps that are their economic equivalent for certain physical commodities that would be subject to exemptions for bona fide hedges. These rules have not been finalized, and their impact on our hedging activities is uncertain. 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). On December 16, 2015, the CFTC adopted final rules establishing margin requirements for uncleared swaps entered by swap dealers, major swap participants or financial end users (though non-financial end users are excluded from margin requirements). While we do not anticipate being subject to margin requirements as a swap dealer, major swap participant or financial end user, application of these requirements to other market participants could affect the cost and availability of swaps we use for hedging. 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 resume 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.

42





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.

While hydraulic fracturing is typically regulated by state oil and natural gas commissions, and other similar state agencies, increased federal interest has arisen in recent years. Please read “Item 1. Business-Operations-Environmental and Occupational Health Safety Matters-Hydraulic Fracturing.” 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.

Laws and regulations pertaining to threatened and endangered species could delay or restrict our operations and cause us 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, and the Clean Water Act. 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 listing of numerous species as endangered or threatened under the ESA through the agency’s 2018 fiscal year.

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. If we were to cause harm to species or damages to wetlands, habitat or natural resources as a result of our operations, government entities or, at times, private parties could seek 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, the government could seek criminal penalties. 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.

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. Please read “Item 1. Business-Operations-Environmental and Occupational Health Safety Matters-Endangered Species Act Considerations.”

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.


43




Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.
 
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 resume 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, 2015, we have identified 1,591 proved undeveloped drilling locations and over 5,013 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, among others, 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 5,013 unproved drilling locations we have identified and scheduled for drilling and 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 resume 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 resume 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, but not limited to:
 
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 and conditions;

adverse weather conditions;

human errors;

facility or equipment malfunctions;

title deficiencies that can render a lease worthless;


44




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 resume paying distributions to our unitholders.
 
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 continue to 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

45




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 resume 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” for additional information about our price risk management activities.
 
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.
 
Our price risk management arrangements in place will not fully mitigate the effect of oil, natural gas and NGLs price volatility, and our revenue and results of operations will be adversely affected if prices remain at current levels or decline further. In the current commodity price environment, we are less likely to hedge future revenues to the same extent as our historical and existing hedging arrangements. As such, our revenues will become more susceptible to commodity price volatility as our commodity price hedges settle and are not replaced.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers, joint interest owners and by counterparties to our price risk management arrangements. Some of our vendors, customers, joint interest owners and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers, joint interest owners 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’, joint interest owners’ 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, joint interest owners and/or counterparties could reduce our ability to resume 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 Executive Vice President of Operations. We do not maintain key person insurance for any of 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.

Conservation measures and technological advances could reduce demand for oil and natural gas.
 

46




Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be unable to compete effectively with larger companies in the oil and natural gas industry, 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. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with our larger competitors that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.
 
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

Risks Related to Our Structure

Our limited liability company agreement limits our duties to our unitholders and restricts the remedies available to our unitholders for actions taken by us that might otherwise constitute breaches of duty.

Our limited liability agreement contains provisions that reduce the standards to which we might otherwise be held by state fiduciary duty law. For example, our limited liability company agreement:
provides that our board of directors and our directors and officers will not have any liability to us or our unitholders for decisions made so long as our board of directors or any director or officer acted in good faith, meaning that our board of directors or such director or officer believed the determination or other action was in our best interests;

provides generally that affiliated transactions and resolutions of conflicts of interest not approved by our conflicts committee and not involving a vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by us in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” we may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

provides that we and our officers and directors will not be liable to us or our unitholders for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining in respect of such matter or question that we or such other persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

Our unitholders are bound by the provisions in our liability company agreement, including those discussed above.

Our limited liability company agreement restricts the voting rights of unitholders owning 20% or more of our units.

Our unitholders’ voting rights are restricted by the provision in our limited liability company agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our founding unitholder and his

47




affiliates or transferees and 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.

We may issue an unlimited number of additional units without common unitholder approval, which would dilute the ownership interest of existing unitholders.

Under our limited liability company agreement, we may, without the approval of our unitholders, issue an unlimited number of additional limited liability company interests of any type, including common units, without the approval of our unitholders.

The issuance by us of additional units or other equity securities may have the following effects:

our existing unitholders’ proportionate ownership interest in us may decrease;

the amount of cash available for distribution on each unit may decrease;

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

the market price of our common units may decline.
 
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. We pay distributions on monthly basis. The value of our units, including common 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 our unitholders. Our limited liability company agreement limits the remedies available to our unitholders in the event our 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 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 us.

48





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

During 2015, the quoted market prices of our common and preferred units fluctuated as follows:
 
 
Low
 
High
Common unit (VNR)
 
$
2.41

 
$
19.50

Series A Preferred unit (VNRAP)
 
$
5.91

 
$
25.23

Series B Preferred unit (VNRBP)
 
$
4.67

 
$
23.76

Series C Preferred unit (VNRCP)
 
$
5.39

 
$
24.24


The market prices of our common and preferred units are subject to fluctuations in response to a number of factors, most of which we cannot control, including, but not limited to:
 
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, and in particular during 2015, 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 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. Under Delaware law, a unitholder who received an impermissible distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the distribution amount. Any such unitholder will have no liability for the account of any such distribution after three years from the date of the distribution unless an action to recover the distribution from that unitholder is conditioned within such three-year period and such unitholder is adjudicated liable in the action. A purchaser of common units who becomes a member 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

49




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, and may negatively affect our ability to issue additional equity or incur debt.
 
Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states or local entities. If the Internal Revenue Service (“IRS”) were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state or local tax purposes, those events would substantially reduce the amount of cash available for payment of distributions on our common units.
 
The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for U.S. federal income tax purposes. A publicly traded partnership such as Vanguard will be treated as a corporation for U.S. federal income tax purposes unless we satisfy the “qualifying income” requirement. Based on our current operations, we believe that we satisfy the qualifying income requirement and will therefore be treated as a partnership. 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. 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.
 
If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to our common unitholders would generally be taxed again as corporate distributions, and no income, gain, loss, or deduction 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 likely be substantially reduced. Therefore, treatment of Vanguard as a corporation would likely 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 units.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such tax on us by any such state will reduce the cash available for distribution to our unitholders.

Our unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income upon cancellation of a portion of our debt, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different from the unitholder’s interest in our distributable cash flow.

Because our unitholders will be allocated taxable income that could be different in amount from the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income. As of February 25, 2016, we have suspended all cash distributions to unitholders and monthly cash distributions to holders of our preferred units. We may engage in transactions to de-lever the Company and manage our liquidity that may result in income and gain to our unitholders. For example, if we sell assets, our unitholders may be allocated taxable income and gain resulting from the sale. Further, we have in the past engaged in, and may in the future engage in, debt exchanges, debt repurchases, modifications of our existing debt, or similar transactions that resulted in, or could result in, “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated gain and income from asset sales and COD income and may owe income tax as a result of such allocations notwithstanding the fact that we have currently suspended cash distributions to our unitholders.

 For example, our issuance on February 10, 2016 of approximately $75.6 million aggregate principal amount of new Senior Secured Second Lien Notes to certain eligible holders of Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 has resulted in the COD income that will be allocated to our unitholders as of February 29, 2016. Some or all of our unitholders may be allocated substantial amounts of such taxable COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect to each unitholder will depend on the unitholder's individual tax position with respect to the units; however, taxable income allocations from us, including allocations of COD income, increase a unitholder’s tax basis in his units.


50




A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our distributable cash flow. This may occur, for example, in the case of a unitholder who owns units in the month in which the cancellation of debt occurs or a unitholder who acquires units directly from us in exchange for a contribution of property whose fair market value exceeds its tax basis at the time of the contribution. Unitholders are encouraged to consult their tax advisors with respect to the consequences of potential transactions that may result in income and gain to unitholders.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or of 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 2017 recommends that publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2022. From time to time, members of Congress also propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of the qualifying income exception upon which we rely for our treatment as a partnership 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. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for U.S. federal income tax purposes.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. 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. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If a unitholder sells his common units, he will recognize gain or loss equal to the difference between the amount realized and his tax basis in those common units. Prior distributions per common unit to a unitholder in excess of the total net taxable income allocated per common unit to such unitholder will decrease such unitholder’s tax basis in that common unit. The amount of this decreased tax basis will, in effect, become taxable income to him to the extent the common unit is sold at a price greater than his tax basis in that common unit, even if the sales price is less than his original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells his common units, he may incur a tax liability in excess of the amount of cash he receives 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

51




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.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units or our preferred units that may result in adverse tax consequences to them.

Investment in our common units or our preferred units by tax-exempt entities, such as individual retirement accounts (“IRAs”), other retirement plans 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 them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If a Vanguard unitholder is a tax-exempt entity or a non-U.S. person, he should consult his tax advisor before investing in our common units or in our preferred units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Due to a number of factors, including our inability to match transferors and transferees of our common units, 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 from the sale of our common units and could have a negative impact on the value of our common units or result in audit 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 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 use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. The proposed regulations do not, however, specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this proration 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 units) may be considered to have 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 our partnership for U.S. 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 are 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 two tax returns (and our unitholders receiving two Schedule K-1s) for one calendar year and could result in a deferral of

52




depreciation deductions allowable in computing our taxable income.  In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s 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 elections and could be subject to penalties if we are unable to determine in a timely manner 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, 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 2017 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