NGL’s bonds have been under stress given the Partnership’s lack of consistent historical performance and the refinancing risk of its capital structure. We think the current commodity price environment will allow producers to maintain adequate drilling activity and thus provide additional volumes for NGL’s water and crude oil logistics segments. The Partnership benefited from this in 3Q23 as it posted record FCF, bought back debt at a discount, and recently announced its intention to redeem their 7.5% Sr Notes that were coming due in November of 2023. NGL will redeem these notes with a combination of FCF and $111.65mm of proceeds from the sale of its marine assets

In summary, the 2026s provide incremental yield relative to the HY & Midstream index with manageable risks that the Partnership is actively working to mitigate in the near term. We believe the current commodity price environment will allow for NGL to at least maintain adequate financial performance, continue to reduce leverage, and addresses its remaining maturities though one or more of the following ways:

• Continued FCF generation focused on debt reduction: Current commodity price levels should provide for stable levels of drilling and thus provide additional volumes for NGL’s water solutions and crude oil logistics segments

• Refinancing to extend maturities: If NGL can consistently perform over the next few quarters, we would expect the Partnership to be able to refinance its 2025s ahead of them becoming current in March of 2024

• Continued non-core asset divestitures: NGL has sold assets in the past in order to reduce debt

• Use the ABL if necessary: Although this would not be a favorable solution, NGL could use its ABL facility to refinance at least a portion of the 2025s

NGL Energy Partners (“NGL” or the “Partnership”) is a publicly traded MLP active in several basins in the United States, including the DJ Basin in Colorado, the Eagle Ford in Texas, and the Permian Basin in New Mexico and Texas. The Partnership operates through three principal segments: Water Solutions (70% of 3Q23 Segment EBITDA), Crude Oil Logistics (19%), and Liquids Logistics (11%). As of 12/31/2022, NGL had total tangible assets of $4.1bn including pipeline systems, storage terminals, water treatment facilities, and disposal wells.

Recent Highlights

In February, NGL successfully amended its ABL to retain its $600mm size and extended the maturity to February of 2026

Later in that same month, the Partnership announced that it intended to call its Sr. Unsecured Notes that were scheduled to mature in November

In March, NGL announced the $111.65mm divestiture of marine assets. Details of the transaction included the following:

• The marine fleet included 13 tow boats and 25 tank barges which provided waterborne transportation of refined products and crude oil.

• The net proceeds of this divestiture would be used to repay the $39mm marine equipment note and repay outstandings under the ABL.

• Management also increased FY23 guidance, including FY23 EBITDA of $630mm vs $600mm, previously.

With the above, the CEO commented that NGL will be able to report leverage of <4.75x (excluding preferred units), as the Partnership was successful in reducing total debt by ~$600mm since 9/30/22.

Sources & Uses and Pro Forma Capitalization

F3Q23 Commentary (Quarter End 12/31/22)

During F3Q23, Adj. EBITDA increased 30.8% to $193mm vs $148mm during F3Q22 as a result of the following:

• Water Solutions: 37% increase in water volumes and higher spot rates in the Partnership’s water segment. This was coupled with lower costs related to less brackish water needing to be purchased during the quarter

• Crude Oil Logistics: High commodity prices and lower expenses offset lower volume related to lower production in the DJ Basin

• Corporate segment included $29.5mm from a legal settlement that offset what would be a negative line item. The Partnership stated that they could not provide further comment on the specific matter

• The positive effects mention were above were partially offset by Lower butane product margins in the Partnership’s liquids segment

• Leverage (ex-pref) decreased to ~5.28x given the above as well as reduced debt related to the Partnerships continued effort to buy back a portion of their bonds at a discount

• Liquidity remains adequate with ~$280.5mm including $4.5mm of cash, plus ~$276mm of availability under the Partnership’s $600mm ABL ($156mm outstanding + ~$168mm of issued L/Cs)

• In February of 2023, NGL announced that they had successfully amended their ABL to remain at $600mm, instead of reducing by $100mm to $500mm on March 31^st, 2023

• After the quarter, NGL sold its marine assets for $111.65mm and redeemed its bonds that were going to be due in November of this year

Enterprise Value & Recovery Analysis

In our recovery analysis we ran two different default scenarios. In both scenarios, we assume the Partnership’s performance degrades over time and 2024E EBITDA is 25% lower than our current estimate. We also assume $171mm of admin claims in both scenarios which equates to 5% of scenario one’s EV at default

Scenario 1: We used the Partnership’s current trading level of 6.75x EV/EBITDA to derive an assumes EV at default of ~$3.4bn.

• This valuation is able to cover the entire debt stack and still have an equity cushion of 57%

Scenario 2: We reduced the EBITDA multiple by 0.50x to 6.25x which is slightly lower than the 6.50x assumption S&P uses. We also assume NGL draws up 60% of its current available capacity under the ABL to fund operations before default

• This valuation would not be able to cover the entire debt stack and there would be a potential loss of ~22%. I believe this would be an acceptable risk of loss given the current yield of the notes being recommended

In conjunction with this issuance, Moody's upgraded CPE's credit rating to B3, from Caa1 previously. Moody’s says the upgrade reflects the "improving credit metrics as oil & gas commodity prices and demand have rebounded, and lower probability of default."

Pro Forma Capitalization

The Company entered the Permian Basin in 2009 and was a pure-play Permian operator from 2013 to 2019, when it gained exposure to the Eagle Ford Shale following the merger with Carrizo Oil & Gas. As of FYE20, Callon had proved reserves of 476 mmboe, of which, 61% is oil. Average daily production was 81 mboe/d in 1Q21.

We recommend going long Callon’s 6.375% Sr Notes due 2026 which currently trades ~90.5, with a yield-to-worst (“YTW”) of ~8.6% (~450bps wider than the Barclays Corp HY Index and ~380bps wider than the E&P HY Index). 

The 2026s provide incremental yield relative to its comps with manageable risks that the Company is actively working to mitigate in the near term.

Callon’s bonds have been trading below par as result of the COVID & OPEC/Russia related collapse in commodity prices occurring only a few months after the Company closed on its merger with Carrizo O&G on December 20, 2019. The completion of the merger resulted in elevated PF leverage that was intended to be reduced over 2020 through non-core asset sales and increased FCF generated through the realization of merger related cost synergies.

We believe that Callon will outperform on synergies and the global economic recovery will support favorable commodity prices, allowing Callon to reduce total debt while funding modest growth. Catalysts to bond price improvement can include one or more of the following:

• Continued asset divestitures: Callon is actively working on divesting non-core assets inherited from Carrizo. This includes their Eagle Ford assets that produce ~22.9 mboe/d (76% oil), which if sold, could achieve a valuation up to ~$800mm based on recent transactions. Proceeds could be used to retire the 2023s and further reduce the RBL outstandings.

• Continued FCF generation focused on debt reduction: Given the rapid recovery in commodity prices supported by strong underlying demand recovery, the Company is prioritizing FCF to reduce total debt.

• A ratings upgrade in the near term would enhance access to capital markets and accelerate the refinancing of near-term maturities: The agency’s current ratings have been in place since before the release of 4Q20 results, and thus do not reflect the improved commodity price outlook nor the recent asset divestitures. If Callon is upgraded in the near term, it would accelerate their plans to refinance the 2023’s.

Current Capitalization

1Q21 Commentary
Note: The Company, along with the broader E&P industry, was negatively impacted in 1Q21 as a result of Winter Storm Uri which occurred in February. This period of extreme cold temperatures required a large portion of the Company’s production to be temporarily shut-in. Callon has since brought 100% of the impacted wells back online.
During 1Q21, Hedge adj revenue decreased ~5.5% y/y to $298mm vs $315mm during 1Q20 as a result of the following:

• ~19.7% decrease in daily production to ~81 mboe/d during 1Q21 vs ~101 mboe/d during 1Q20. The decrease in production was primarily due natural decline and producing wells being temporarily shut-in during February as a result of Winter Storm Uri.

• $62.3mm in realized losses from the unfavorable effects of the Company’s commodity hedges.

• The negative effects mentioned above were partially offset by a 19% improvement in pre-hedge realized commodity prices (~$40.9/boe during 1Q21 vs ~$34/boe in 1Q20).

Lease operating expenses (“LOE”) decreased ~2.6% y/y on a per barrel basis to $5.55/boe during 1Q21 vs $5.70/boe in 1Q20 due to the Company’s continued efforts to further improve overall efficiencies after the addition of Carrizo's producing assets, partially offset by the distribution of fixed costs over lower overall production.
Gathering & transportation expenses increased ~57.7% y/y to $2.47/boe during 1Q21 vs $1.57/boe during 1Q20, primarily due to oil transportation agreements which were entered into after 1Q20.
Cash G&A increased ~2.6% y/y on a per barrel basis to $0.88/boe during 1Q20 vs $1.68/boe during 1Q19, primarily resulting from the increased production and headcount reductions after the merger with Carrizo.
EBITDAX decreased to ~$171mm during 1Q21 vs ~$217mm in 1Q20, as a result of the above.
Leverage increased on an LTM basis to 4.5x at 3/31 vs 4.2x at FYE20 given the lower LTM EBITDAX vs FYE20, however we expect leverage to resume its trend lower in future quarters. We note that the total leverage test of <4.0x Total Debt / EBITDAX under the RBL has been suspended until 1Q22. The Company is still beholden to a <3.0x Secured Debt / EBITDAX covenant.
Liquidity remains adequate at $650mm at 3/31 consisting of $24.4mm of cash and $626mm of availability under the Company’s RBL which currently has $1.6bn of elected commitments.
Recent Asset Sale: After the quarter, Callon sold certain non-core properties in the Delaware Basin and received gross proceeds of $40mm. The Company will use the net proceeds to continue CPE’s debt reduction strategy.

Model Output

Asset Value & Recovery Analysis
We ran an EV analysis on Callon using both an NPV approach and a market-based approach to derive a total EV of ~$4.4bn. Our NPV analysis on the reserves used a 10% discount rate and price deck used in the financial model. This resulted in a total 1P reserve valuation of $4.72bn, with a PDPs making up ~$2.28bn (or ~48%) of that total.

• In normal market conditions, Callon should be able to receive a bid for an amount close to our 1P valuation. In that scenario, we would recover 100%. If the company were to focus all their net cash flow to debt repayment, the 1P  reserves would repay all outstanding debt within 7 years, or 29% of its economic life.

• In our market-based approach, we used EV/EBITDAX multiple to derive an implied EV of $4.1bn. This is based on our 2022E EBITDAX estimate of $1bn, and a 4.0x multiple from the peer median of comparable companies.

• In a liquidation scenario with a weak A&D market, a potential buyer may only be willing to pay for PDP reserves. In this downside scenario, we would recover ~56%.

Reserve Valuation

EV / EBITDAX Valuation